The Netherlands is transitioning towards a fully renewable energy system, aiming to achieve an almost entirely renewable energy supply by 2050. Green hydrogen, produced via water electrolysis powered by renewable energy, offers a key solution for decarbonising energy-intensive sectors. However, high production costs remain a major barrier to widespread adoption. This study investigates the cost-optimal design of a hybrid renewable energy system combining solar PV, onshore wind, and battery storage to supply a 200 MW electrolyser in De Koog, the Netherlands.
A simulation model was developed in Python, incorporating hourly wind and solar generation data, electrolyser operation with on/off stack control, battery charging and discharging, and system degradation over a 20-year lifetime. Multiple system scenarios were evaluated by varying installed capacities, battery sizes, and minimum stack operation rules. Economic performance was assessed using key indicators, including hydrogen sales price, levelised cost of hydrogen (LCOH), net present value (NPV), internal rate of return (IRR), and payback time. Additionally, stack and battery replacement costs were considered. Results show that the cost-optimal system for the chosen location, De Koog, is dominated by wind-only systems, with the electrolyser operating at a capacity factor of 0.659. Inclusion of a small battery provides
minor operational flexibility, increasing annual hydrogen production slightly from 22.98 to 22.99 million kg, but has a negligible effect on hydrogen sales price (7.442–7.444 €/kg), NPV, LCOH, IRR, or payback time. From year 8 onwards, stack replacement costs remain constant, as stacks are replaced annually and battery replacement is scheduled after 13.5 years, leading to only a limited and predictable increase in total system costs. Electrolyser stack granularity affects operational efficiency: smaller stacks reduce curtailment without storage but slightly limit battery utilisation when included.
The findings indicate that the economic performance of green hydrogen production is primarily driven by the balance between renewable generation and electrolyser operation. In particular, the renewable to-electrolyser capacity ratio plays a key role, while battery storage has only a minor influence in the cost-optimal configuration. For the analysed Dutch coastal site, the lowest hydrogen production costs are achieved with a moderately oversized wind capacity, an electrolyser operating at an intermediate capacity factor, and minimal battery integration. However, the optimal capacity ratio and the economic value of battery storage are strongly location-specific and depend on local resource conditions and system design assumptions. This study provides a comprehensive techno-economic assessment of hybrid renewable energy system design, offering practical guidelines for optimising component sizing to achieve cost-efficient green hydrogen production in the Netherlands and supporting the transition to a low-carbon energy system.

The Levelized Cost of Hydrogen (LCOH) is commonly used to evaluate the economic performance of electrolytic hydrogen production. In many studies, electricity costs are represented by static average prices, while assuming simplified operating profiles. This simplification neglects the temporal variability of electricity prices in liberalized power markets and limits the representation of flexible electrolyzer operation.

This thesis develops a techno-economic LCOH framework that incorporates hourly electricity prices, renewable generation profiles, and operational constraints of an alkaline electrolyzer. A bottom-up modeling approach is applied, aggregating hourly operating decisions into discounted lifetime costs. A daily dispatch optimization algorithm is introduced to determine the operation of the electrolyzer based on electricity prices, expected hydrogen revenues, and solar availability, while accounting for start-up penalties, efficiency degradation, and stack replacement.

The framework is applied to a case study of a 1.2 MW alkaline electrolyzer coupled with a large solar field in the Netherlands using historical market data. The results indicate that price-responsive operation can reduce LCOH relative to continuous operation, primarily by avoiding periods of high electricity prices, although this leads to lower overall hydrogen production volumes. Compared with purely solar-following operation, cost reductions are achieved at the expense of higher carbon emissions as a result of increased reliance on grid electricity.

Overall, the study shows that incorporating electricity price dynamics and operational constraints can materially affect LCOH estimates and provides a more transparent basis for evaluating grid-connected electrolytic hydrogen production under volatile electricity markets.

As the energy transition accelerates, there is growing interest in exploring different renewable energy sources to help reduce emissions from heating and electricity. One of the more promising options, under the right conditions, is geothermal energy, which can provide a stable and relatively low-carbon supply of heat and/or power. In the Netherlands, medium-depth (>500 m) geothermal heat has mostly been used for heating greenhouses, with electricity production from geothermal sources not yet explored.

This thesis provides a techno-economic assessment of medium-depth geothermal energy systems in South Holland, the Netherlands, evaluating their potential to meet local heat and electricity demands sustainably and with a profit. Two case studies were analyzed in this thesis. The first investigated a geothermal district heating system for the TU Delft campus, incorporating a large-scale heat pump to increase heat extraction from the reservoir. The second examined a combined heat and power (CHP) system for the Royal IHC facilities in Kinderdijk, based on an Organic Rankine Cycle (ORC). The work relied on thermodynamic modeling together with subsurface and economic simulations to select working fluids, size the main components, and assess economic indicators such as Levelized Costs of Heat/Electricity (LCOH/LCOE), Net Present Value (NPV), payback times, and internal rate of return (IRR).

The findings reveal a sharp difference in feasibility between the two cases. The geothermal heat pump project in Delft proved to be promising for district heating applications, whereas the ORC-based power generation system proved to be both technically and economically unviable under the assessed conditions, mainly due to the low temperature of the geothermal brine and the small scale of the project. A subsequent evaluation of a heat pump alternative for the Kinderdijk site indicated limited economic competitiveness under the current market price assumptions for heating.

Overall, the work suggests that the viability of geothermal projects is highly dependent on the quality of the geothermal resource, the scale of implementation, and the end-use requirements. Integrating heat pumps with medium-depth hydrothermal resources appears as a technically promising and financially attractive strategy for decarbonizing district heating networks, whereas low-temperature ORC systems for power generation remain unsuitable in regions with insufficient subsurface temperatures. The study shows the importance of site-specific assessments in ensuring the successful deployment of geothermal energy systems.

The economic viability of a hydrogen economy revolves around efficient and scalable methods for its transportation and storage. Liquefaction presents a key pathway by increasing hydrogen’s volumetric energy density, though current industrial plants are hampered by high energy consumption and costs.
While conceptual models offer pathways to higher efficiency, they often lack the detailed technical and economic analysis needed to validate their feasibility, particularly for systems based on the Brayton cycle.
This thesis presents a comprehensive framework for the process modeling, viability assessment, and techno-economic analysis of a large-scale hydrogen liquefaction plant based on a conceptual Brayton cycle. A central contribution is the detailed modeling of the critical ortho-para hydrogen conversion, which was simulated within a catalytic Plate-Fin Heat Exchanger (PFHX) using a specialized Python-based model integrated with a full-plant Aspen HYSYS simulation. The study also addresses the effective management of excess cold hydrogen gas; an initial investigation into using an ejector for recirculation was conducted, but this approach was ultimately discarded as it did not yield economic improvements. A final, optimized hybrid Brayton-Claude cycle featuring an efficient cold gas recirculation loop was developed, enabling a plant capacity of 86 tonnes per day (TPD).

The techno-economic analysis of the final design was performed using the Aspen Process Economic Analyzer (APEA). In the baseline scenario, assuming an electricity price of 0.1 €/kW h, the plant achieved a Specific Liquefaction Cost (SLC) of 1.51 €/kgLH2 and a Specific Energy Consumption (SEC) of 6.983 kWh/kgLH2 in the baseline scenario.

Moreover, sensitivity analyses show a further reduction in SLC and SEC in the scenario using power recovery from the turbines: 1.49 €/kgLH2 and 6.723 kWh/kgLH2 respectively. Additionally, electricity price is the dominant factor influencing plant economics, with the long-term cost target of below 1.00 €/kgLH2 being achievable at an electricity price of 0.035 €/kW h. Future projections, which account for reduced design allowances as the technology matures to a ”Proven Process,” suggest a potential SLC reduction of 4.64%.

In summary, this thesis establishes a robust techno-economic framework for Brayton-cycle based liquefaction, demonstrating its viability while highlighting the critical interplay between advanced process modeling, component efficiency, and energy costs in achieving a competitive large-scale liquid hydrogen supply chain.

This thesis evaluates the technical and economic feasibility of producing methane (CH4) via the electrochemical reduction of carbon dioxide (CO2), offering a pathway to valorize captured CO2 while integrating surplus renewable electricity into established natural gas infrastructure. A dual-modeling framework was developed: an Excel-based electrolyzer model captures key electrochemical parameters including Faradaic efficiency (FE), current density (CD), cell voltage, and resulting power demand while an ASPEN Plus simulation rigorously models downstream separation, employing cryogenic distillation to achieve high-purity CH4 and co-products. The study systematically investigates multiple operational scenarios, reflecting variations in electricity pricing (including projected low-LCOE renewables), CO2 feedstock costs (derived from different capture strategies), and market values for methane and by-products. A detailed techno-economic assessment quantifies capital expenditure (CAPEX) requirements, dominated by electrolyzer sizing due to constraints on CD and FE, and operational expenditure (OPEX), primarily driven by electricity consumption. Sensitivity analyses reveal that electricity price, electrolyzer CAPEX (tied to CD and cell voltage), and product stream valuations are the most influential parameters affecting the net present value (NPV). Base case simulations show that under current market conditions (25=C/MWh electricity, 9,000=C /m2 electrolyzer CAPEX), the process yields a strongly negative NPV. However, scenario analyses demonstrate that moderate improvements across several fronts, reducing cell voltages to 2.5V, increasing CDs beyond 5000 A/m2, and securing electricity prices under 15=C /MWh can collectively transition the process towards economic breakeven within a 30-year project horizon. Environmental performance was assessed via a simplified CO2 balance, indicating that for each ton of CH4 synthesized, approximately 2.75 tons of CO2 are sequestered. However, this benefit is partially offset by indirect emissions from electricity generation, underscoring the need to combine the process with low-carbon power sources to ensure genuine climate mitigation. This comprehensive analysis highlights both the promise and the formidable challenges of industrialscale CO2 electroreduction to methane. It underscores the critical need for integrated approaches combining advancements in catalyst selectivity and stability (to improve FE toward CH4), process intensification to achieve higher CDs with minimized overpotentials, and supportive policy mechanisms such as carbon pricing or renewable integration incentives. Ultimately, the findings provide quantitative benchmarks and strategic direction for advancing CO2-to-CH4 electrolysis towards economically and environmentally viable deployment.

Hydrogen is getting great attention as a key energy carrier for a cleaner energy future, with demand projections up to 20% of global energy demand by 2050. However, the low volumetric density of hydrogen leads to a challenge for storage and transport purposes, making liquefaction a promising solution that also ensures high purity. However, at the current time, the high energy consumption of liquefaction remains a major obstacle. Within this process, the precooling stage is the second most energy-intensive step, covering the broadest temperature range but offering flexibility in terms of refrigerant choice, cycle configuration, and operating conditions.

However, most of the study of the hydrogen precooling omits economic analysis, refrigerant freeze-out discussion, and employs a portion of a non-environmentally sustainable substance as the refrigerant. This study focused on addressing the gap by conducting multi-objective optimization (MOO) on specific energy consumption (SEC) and levelized precooling cost (LPC) to find out the optimal trade-off between the technical and economic competitiveness of the precooling stage, while ensuring the freeze-out risk in the streams was avoided and using environmentally friendly mixed refrigerant (MR) mixtures.

Two cycles, namely single mixed refrigerant (SMR) and dual mixed refrigerant (DMR), are modeled in Aspen HYSYS V12, where the configurations are defined based on freeze-out consideration. Nine MR mixtures for SMR and DMR are defined based on their thermophysical properties. A Non-dominated Sorting Genetic Algorithm-II (NSGA-II) algorithm was used for MOO through the pymoo library package in Python, which was then coupled with Aspen HYSYS. The decision variables to be optimized include MR composition, MR flow rate, compressor discharge pressure, and JT valve outlet pressure. Several constraints are also introduced, such as vapor fraction at the inlet compressor, minimum internal temperature difference (MITD) of heat exchangers, JT valve temperature difference, and several temperature constraints to ensure thermodynamic behavior is not violated.

In this study, Mixture 8 (for SMR) and Mixture 6 (for DMR) appear to be the top-performing mixtures, achieving specific energy consumptions (SEC) of 1.25 kWh/kg_H2 and 1.13 kWh/kg_H2, respectively, with levelized precooling costs (LPC) of €0.47/kg_H2 and €0.60/kg_H2. The study indicates that aligning the boiling points of mixed refrigerant components to enhance temperature glide, combined with tuning of operating conditions, is the key to achieving both energy efficiency and cost competitiveness. Furthermore, the optimized results in DMR also suggest that the intermediate-compression stage in the MR2 cycle could be removed.

From the sensitivity analysis, it was observed that as the precooling temperature target increased, the gap in SEC between the SMR and DMR configurations narrowed. Starting from 95 K, both systems reached similar SEC values, highlighting equal technical performance. However, the LPC further SMR dominant over the DMR. This indicates that beyond this temperature target, DMR was no longer economically competitive. Additionally, variations in pressure drop across heat exchangers and coolers had a stronger impact on the SMR configuration. The percentage increase in SEC and LPC was more severe due to the accumulation of pressure losses within a single-loop cycle. In contrast, the DMR system distributes losses across two separate loops, making it less sensitive to pressure drop effects.

The global energy transition is one of the most urgent technological and societal challenges of the 21st century. To achieve climate goals, it is essential to reduce the use of fossil fuels and replace them with sustainable alternatives. In this context, green hydrogen is receiving increasing attention, particularly as asolution for sectors where direct electrification is difficult or unfeasible, and as a means to balance the intermittency of renewable energy sources. However, hydrogen production via water electrolysis remains energy-intensive and costly, particularly when powered by fluctuating sources like wind. To improve economic viability, system-level optimisation must account for technical phenomena such as dynamic efficiency, degradation, gas crossover, and the performance of power electronics.
This thesis investigates the dynamic behaviour and optimal sizing of a directly coupled wind-powered alkaline electrolyser system, with the aim of minimising the Levelized Cost of Hydrogen (LCOH). Although static operating conditions are often assumed in existing models, this work addresses gaps in the literature by developing a time-resolved simulation model that includes wind variability, dynamic efficiency, degradation effects, realistic operational limits of the electrolyser, and time-dependent efficiency of power electronics.
An electrolyser model was developed and implemented in Python using an Electrical Equivalent Circuit (EEC) approach. An initial analysis compared intra-hour wind power fluctuations with hourly averages, revealing that the impact on hydrogen conversion efficiency was negligible (<0.06% over three 3-hour periods). Given this minimal difference and the widespread availability of hourly wind data across numerous locations, hourly wind data was deemed sufficiently accurate for system-level analysis.
The model was subsequently applied to evaluate system performance across 38 onshore European locations using 2015 wind data, assuming a constant configuration of a 2MW wind turbine coupled to a 1380kW electrolyser (69% ratio). For each location, the wind turbine and electrolyser capacity factors were calculated to assess the geographical variability in system utilisation. In addition, two Dutch sites, one coastal and one inland, were studied in greater detail to analyse annual operational behaviour, power electronics impact, conversion efficiency, hydrogen yield, and degradation patterns. Finally, lifetime simulations over 20 years were performed to evaluate system economics under varying electrolyser sizes, three cost scenarios, and two discount rates. Results showed that optimal electrolyser sizing is highly location-dependent and influenced by design objectives: the size yielding the highest hydrogen production is not necessarily the one that results in the lowest LCOH. In fact, the LCOH-optimal size was consistently smaller. Moreover, cost scenarios affected optimal sizing, with higher capital costs favouring slightly larger systems to offset investment through increased hydrogen output.
Time-resolved modelling further revealed the importance of minimum load constraints (to avoid gas crossover) and degradation effects, which influence system utilisation and stack replacement timing. While lifetime hydrogen production estimates from the dynamic model did not deviate significantly from those based on static assumptions, the dynamic approach enabled more accurate performance forecasting and degradation tracking. This research highlights the necessity of time-resolved modelling for techno-economic assessment of wind-powered hydrogen systems. The developed framework provides a comprehensive foundation for future optimisation studies and supports more accurate design and investment decisions for renewable hydrogen deployment.

Catalytic methane pyrolysis (CMP) is a potential method to produce clean hydrogen without direct COx emissions, but is not cost-competitive with current hydrogen production techniques yet. A strategy to increase the cost-competitiveness is to purify and sell the nanocarbon by-product. This paper outlines the process design, modelling and analysis of purifying carbon nanofibre (CNF), produced by CMP, with acid leaching.

CNF produced by CMP with a Ni-SiO2 catalyst was used for this study and initially contains 4700 ppm of nickel. The baseline scenario of the designed process has a production capacity of 20,000 tonnes per year and includes acid leaching with HCl, liquid removal and post-treatment steps. The techno-economic analysis showed a Levelized Cost of Purification (LCOP) of 10.09 $/kg and a Net Present Value (NPV) of 1.48 billion $ for the baseline scenario. The process is very profitable due to the assumed high selling price of 25 $/kg. However, the conversion of nickel is only equal to 5.15 %, leaving 4460 ppm of nickel in the CNF product while the desired nickel content is below 300 ppm. The low conversion indicates that the quality of the CNF product is barely improved and that the assumed selling price is probably too high. The acid leaching kinetics are modelled using literature on acid leaching with HCl of nickel from a Ni-Al2O3 spent catalyst. Acid leaching experiments of nickel from CNF with H2SO4 showed a more positive average nickel conversion of 70.9 % so far. The leaching kinetics still have to be determined for a variety of acids and will be necessary to model the leaching more accurately.

Sensitivity analyses showed that the impact of the acid waste price on the LCOP was the largest of the economic parameters with ±2.5 $/kg variation, followed by the electricity price. The acid feed price also had a significant impact on the LCOP. The high impact of the acid waste and feed price showed a need for the implementation of an acid recycle. A Monte Carlo analysis indicated a robust process design under economic uncertainties. The mean of the LCOP was equal to 10.12 $/kg and the standard deviation was equal to 0.90 $/kg.

Two improved design cases of the baseline scenario are presented. The first includes changes to the reactor temperature, residence time, acid molarity, ratio of CNF feed to acid feed and the inclusion of an acid recycle. The conversion is improved to 61.04 % with an LCOP of 24.68 $/kg. The second design case builds upon the first and includes further changes to the residence time and ratio of CNF feed to acid feed. Furthermore, the reactor setup is changed to three reactors placed in series for the second design case. The conversion is increased to 93.95 %, leaving only 285.66 ppm of nickel in the CNF product. The LCOP is equal to 21.84 $/kg, but a total of 90 reactors are required. While the process is profitable and the nickel content in the product is below 300 ppm, questions arise whether the second improved design is practical.

The present work investigates the valorization of wine industry residues through the production of advanced biofuels, focusing on grape pomace as a representative lignocellulosic feedstock. The study aims to assess the technical and economic feasibility of converting this residue into liquid fuels via hydrothermal liquefaction (HTL)and to compareits performance against the bioethanol basedpathway currently implemented by Destilerías y Biorefinerías Zambrana, S.A. in the Basque Country.

The increasing dependence on fossil fuels for energy and chemicals has caused a significant rise in atmospheric CO2 concentrations, leading to global warming and ecological imbalances. Electrochemical CO2 reduction (CO2R) has emerged as a promising technology to mitigate CO2 emissions while converting it into valuable chemicals and fuels, such as ethylene, ethanol, and acetic acid. With its compatibility with renewable energy sources, moderate operating conditions, and potential for high selectivity, CO2R is positioned as a key player in the transition toward a carbon-neutral economy. However, challenges such as mass transfer limitations, impurities in industrial CO2 feedstocks, and economic feasibility hinder its large-scale implementation. This thesis aims to address these challenges through experimental studies, process design, and techno-economic analysis. The combined findings also reveal key limitations that must be addressed for large-scale deployment.

The viability of hydrogen as a sustainable energy carrier is significantly affected by the costs linked to its transportation and storage. Transporting and storing hydrogen in its liquid form offers remarkable advantages, as liquid hydrogen has unique characteristics, including lower weight and volume, as well as a higher energy content compared to gaseous hydrogen. However, current industrial hydrogen liquefaction processes face significant challenges related to efficiency and cost, with a second-law efficiency of less than 25% and costs ranging from 2.5-3.0 US$/kgLH2.

Large energy storage systems can address the issue of energy demand fluctuations in renewable energy grids by storing excess energy produced and compensating for any energy shortfalls. The development of hydrogen energy storage systems will thus support the advancement and increased utilization of renewable energy sources. The demand for liquid hydrogen is expected to rise in the near future, driven by environmentally friendly applications and use in mobility sector. As a result, large-scale hydrogen liquefaction (LHL) plants will become increasingly important in the clean energy efficient hydrogen supply chain.

This thesis aims to develop a Large-scale Hydrogen Liquefaction (LHL) plant based on the Brayton cycle concept of 86 TPD. The plant is modeled using Aspen HYSYS, with preliminary designs for key equipment—such as compressors, turbines, and plate-fin heat exchangers, ensuring compatibility with current technological constraints. State properties of the fluid used in the design of compressors and turbine equipment were obtained from REFPROP software, utilizing the Peng-Robinson Equation of State (EOS). For the design of plate-fin heat exchangers, Aspen Exchanger Design and Rating (EDR) was employed. Subsequently, a techno-economic analysis was conducted using the Aspen Process Economic Analyzer (APEA) to estimate both capital and operating expenditures, based on the process simulation model and preliminary equipment designs.

The specific energy consumption (SEC) of the plant, accounting for power recovery from turbine shafts, is determined to be 6.9025 kWh/kgLH2. The plant’s exergy efficiency is calculated at 43.665%, and the specific liquefaction power is found to be 3.014 kWh/kgLH2. Assuming an electricity price of 0.1 €/kWh, modelled 86 TPD Brayton-cycle concept yielded specific liquefaction cost (SLC) of 1.57 €/kgLH2.

A sensitivity analysis was conducted to identify the parameters that influence the specific liquefaction cost (SLC) of the plant. The analysis focused on two key parameters: 1) electricity price and 2) feed pressure. The results reveal that fluctuations in electricity prices have a substantial impact on the plant’s economic performance. Additionally, the analysis indicates that the plant’s efficiency and economic viability are significantly sensitive to decreases in feed hydrogen pressure.

De-carbonizing aviation is necessary for a sustainable future, and using hydrogen in a fuel cell, that produces water, can greatly reduce greenhouse gas emissions. Achieving higher gravimetric energy density with hydrogen compared to conventional jet fuels, involves storing it in cryogenic liquid form. Along with it, its cryogenic temperature range not only enables its use as chemical energy storage but also as a potential heat sink. However, rapid vaporization, known as boil-off, limits the long-term storage of liquid hydrogen in fuel tanks, requiring regular venting due to self-pressurization over time. Additionally, hydrogen needs to be heated to the fuel cell’s operating temperature before being used as a reactant. Understanding these requirements, this thesis focuses on three areas: predicting the maximum boil-off rate of liquid hydrogen while charging the fuel tank using a MATLAB simulation and the boil-off rate during the flight journey using a validated software called BoilFAST to understand the feasibility of retrieving the boil-off for its integration with the fuel supply; designing a fuel supply system that integrates the boil-off gas with the vaporized liquid hydrogen supply line to the fuel cell system; and integrating the cryogenic energy of hydrogen with a ram air-cooled vapor compression refrigeration system (VCRS) based thermal management of fuel cell, with the intention of reducing its parasitic load and improving system compactness. Two methods were used for the thermal integration: VCRS involving fuel cooled heat exchangers that function as an intercooler and as a separate de-superheater before a ram air-cooled condenser; and VCRS with a separate single-phase, 52\% ethylene-glycol based serial cooling circuit with multiple fuel cooled heat exchangers (FCHX). This resulted in a significant reduction of parasitic load by 13.4% and 26% when integrated with the intercooler system and single-phase serial cooling system, respectively. The study also examined the expected additional component weight, considering the aviation sector's preference for lighter systems. The findings demonstrate that the holding time of the fuel for minimum 13 minutes after tank filling and before the start of the propulsion system unit can allow a controlled amount of boil-off gas to be integrated with the fuel supply. Utilizing cryogenic energy for thermal management can significantly enhance the system's coefficient of performance by 15.3% and 33.3% respectively. Future work should involve experiments to obtain actual boil-off rates at different ambient exposures of fuel tank, tests on sloshing effect due to turbulence during flight journeys, analysis of thermal stress effects in cryogenic heat exchangers due to high temperature gradients, and testing new compatible mixed refrigerants with improved thermal properties for optimum cryogenic heat exchange.

The problem of global warming is becoming every day more and more pressing, leading to the necessity of reducing harmful emissions especially in the shipping sector. Most ships sail with Internal Combustion Engines, reason why it is beneficial to keep using this system, with the prospect of being able, though, to cut down on the emissions. This can be done implementing new fuels, such as PODE and methanol. These two fuels can largely reduce the emissions without the need for major changes to the engine system. Also, they can be produced in an ”eco-friendly” way, reducing the emissions also during the production process. In this study, the working characteristics of a dual fuel engine, considering methanol and PODE are analysed, as well as the production process of PODE from methanol, process that happens on board of the vessel itself. For the dual fuel engine the analysis showed that different ratios of methanol and PODE can be considered for the dual fuel engine and that this system can deliver the required power output. The plant design resulted in a plant consisting of two reactors and a separation system. At last, the necessary fuel can be produced by a plant that is small enough to fit on the ship and not have to reduce the capacity of the vessel significantly.

The percentage of electric vehicles (EVs) in the automotive sector is expected to quadruple by 2040, causing concern regarding the material supply required for the production of lithium-ion batteries. Currently, a substantial part of these materials, such as cobalt and lithium, are subject to non-circular economies, have a substantial environmental impact and are mined in countries with unstable political situations.
Up until now, numerous companies have attempted to resolve these issues through the use of pyro- and hydrometallurgical recycling methods. However, they are yet to meet the mandated recycling goals put in place by the European Commission. This enhances the urgency for the development of a novel, efficient and scalable technology for the recovery of valuable material from spent lithium-ion batteries.
In order to achieve such a development, this study proposes to incorporate Bipolar Membrane Electrodialysis into the standard hydrometallurgical recycling approach. During the course of this research, a prototype of this technology was realized and used to investigate its effectiveness. For practical reasons, the research focused exclusively on the metal and acid recovery from leached LCO cathode material.
Within the subsequent experimental phase of this research a critical issue was identified. Namely, the tendency of divalent cobalt ions to precipitate in non-acidic media. The resolution to this issue required the incorporation of Donnan dialysis into the built BPMED setup, which was used to adjust the acidity of the solutions within the different electrolytic compartments.
Ultimately, this approach led to the respectively recovery of 14 and 22 percent of the lithium and cobalt initially present in the feed solution. Simultaneously, the study recovered a significant amount of the starting leaching agent in the form of 0.6 M nitric acid. Whilst additional optimizations are required to improve the recovery efficiencies, the study successfully demonstrates a proof of concept of the proposed solution.

Hydrogen is seen as a clean energy carrier that will aid in phasing out fossil fuels, and liquid hydrogen will likely play a role in the global hydrogen economy. However, Life Cycle Assessment researchers and process engineers widely report having insufficient means to accurately assess the environmental impacts of hydrogen liquefaction. This thesis presents an LCA study of hydrogen liquefiers based on current public data and literature. Additionally, a simplified model for hydrogen liquefaction was developed to aid future LCA researchers. An original Life Cycle Assessment of hydrogen value chains incorporating liquefaction is also included. The environmental harm was calculated in the form of direct monetary prevention costs, using the increasingly popular Eco-cost method. The environmental impacts of various sizes and types of hydrogen liquefiers are compared, while hotspots of environmental harm were determined. The main findings indicate that the primary source of environmental impact for hydrogen liquefaction is power consumption, with refrigerant leakage being insignificant as long as hydrocarbons are used for the precooling mixture.

As the global economy continues to expand, the demand for natural gas has surged, leading to a significant increase in LNG consumption. LNG offers a pipeline-free transportation solution, but its integration with standard natural gas systems requires an evaporation process. Currently, LNG evap- oration is commonly achieved through self-consuming processes, seawater, or air evaporators. However, there is growing interest in leveraging the cold exergy of LNG for other processes. With carbon storage gaining prominence due to climate change concerns, integrating LNG evaporation and CO2 liquefaction systems could offer potential cost reductions in the overall process. Singapore could be an optimal location for such an integrated system due to the increasing LNG imports and the desire to become carbon-neutral requiring CO2 exports. The research of this thesis therefore will be: ”How can the LNG evaporation process be integrated with a carbon-dioxide liquefaction process at an LNG terminal in Singapore?” Existing research primarily focuses on self-consuming processes or CO2 purification, leaving a gap in understanding non self-consuming systems for integrating LNG evaporation and CO2 liquefaction at cryogenic temperatures. This study aims to fill this gap by comparing various heat transfer systems and evaluating their technical and economic feasibility. Three systems have been set up to be compared: a Direct heat exchanger system, an intermediate Propane loop and an Organic Rankine cycle. The Organic Rankine cycle has been optimized based on the net power output, first and second law efficiency of the system. Subsequently, the three systems have been compared showing that the Organic Rankine cycle is dominant in technical performance, both being self sustaining and holding a second law efficiency of 82.3%, which is 5% higher than the other designed systems. Additionally, the Organic Rankine cycle has a specific net power output of 7.3 kWh per ton CO2 liquefied, which can be utilized for other processes. After this, a financial assessment is performed on the three systems based on the internal rate of return and net present value of the systems. The Direct heat exchanger showed to be dominant in terms of internal rate of return and net present value ($313M and 534.1%, respectively). The Propane loop would be the second best system in terms of internal rate of return (79.5%). The Organic Rankine cycle could provide a higher net present value than the Propane loop ($285M and $267M, respectively), assuming that constant flows could be guaranteed and no additional evaporator is required. The Direct heat exchanger would be the financial best choice for Vopak but is limited by the high risk of frost formation in the exchangers, making it an unfit choice for this application. While the Organic Rankine cycle could provide an interesting alternative due to it’s higher net present value and power generation, the system complexity, generated electricity value uncertainty and initial investment make it a less attractive choice. Based on the techno-economic analysis in its entirety, the Propane loop was determined to be the best system to combine CO2 liquefaction and LNG evaporation.

The increasing adoption of hydrogen in industrial applications is driven by its potential to decarbonize various industries. Among the various methods of hydrogen production, water electrolysis is considered one of the environmentally friendliest options. However, hydrogen produced from water electrolysis contains impurities such as oxygen and water vapour, and the required level of purity varies depending on the specific industrial application. To address this issue, catalytic recombination of hydrogen and oxygen into water is selected as a method for oxygen removal due to its high efficacy in completely converting oxygen. Subsequently, hydrogen drying is achieved using Pressure Swing Adsorption (PSA) following the catalytic recombination process. This thesis work primarily focuses on the modelling and sizing of adsorption columns within the PSA system. One-dimensional dynamic models describing the pressurization, adsorption, depressurization, and desorption steps of PSA are mathematically derived and developed in Python. The adsorption modelling approach is validated using experimental data from a scientific paper. Insightful information was obtained during the model validation process, shedding light on the consequences of the assumptions made to simplify the energy balance, as well as revealing the decrease in adsorption capacity during the pressurization process. The PSA system is designed to process 400 kg of hydrogen per day with the aim of reducing the water vapour content below 5 ppm. While pressure plays a central role in PSA control, it has been discovered that the primary design challenge relates to temperature control within the operating range. Therefore, adsorption column sizing is optimized, taking into account PSA performance and required energy input. A sensitivity analysis is conducted to identify the optimal adsorbent, considering zeolite 3A and silica gel. Based on the results, a column length of 2 meters and a diameter of 0.0914 meters are considered optimal for zeolite-packed adsorption columns, resulting in a productivity of 35.62 mol/hr/kg and requiring 50.21 kJ during the desorption step. The optimal size for silica gel-packed adsorption columns has not been determined due to a significant temperature drop during desorption, which could risk ice formation and subsequent flow blockage. Nevertheless, silica gel, with its higher adsorption capacity leading to a longer adsorption step, remains a viable option from an operational perspective and should not be disregarded as a potential choice.

To comply with the Paris Agreement, the Dutch government has launched an energy transition process, with the goal of replacing coal and natural gas-based electricity with renewable sources. The intermittent nature of renewable electricity necessitates the installation of an energy storage system to balance supply and demand. Hydrogen is a potential energy storage and transport medium. However, its production is currently more expensive than natural gas, and storage and transport are energy-intensive due to its low density. Because the infrastructure necessary for the hydrogen supply chain necessitates significant capital investments, a techno-economic analysis of various techniques of hydrogen production, compression, storage, and transport is required.
The aim of this thesis was to evaluate the levelized costs of hydrogen at various phases of supply chain, from hydrogen production to utilization. In order to accomplish this task, a literature review was conducted to identify the most promising methods in hydrogen production, compression, storage and transport followed by developing mathematical models of various technologies. According to the literature review, water electrolysis using electrolyzers such as alkaline, polymer electrolyte membrane (PEM), and solid oxide was shown to be techno-economically feasible. The literature review also revealed that centrifugal and diaphragm compression, pipeline transmission, and salt cavern storage were all techno-economically feasible technologies. These technologies’ steady-state mathematical models were built for scaling and techno-economic analysis. In the end, learning curves were applied for electrolyzers to predict the cost reductions in future.
According to the results of mathematical modeling, hydrogen production contributes the most to total levelized costs of supply chain followed by overall compression costs. Moreover, capital costs of electrolyzer stack and electricity costs significantly influence the levelized costs of hydrogen production. For 1 MW electrolyzer capacity and average capital and operating costs of electrolyzer stack, alkaline electrolysis is currently the most cost-effective technique of producing hydrogen with levelized cost of hydrogen (LCOH) calculated to be 3.69 €/ kg, followed by solid oxide electrolysis (4.55 €/kg).However, the use of learning curves indicates that by 2050, solid oxide electrolysis may be the most cost-effective technique of producing hydrogen with projected levelized cost of 1.72 €/kg. The pipeline compression costs were found to be around 0.065 €/ kg whereas diaphragm compression costs were found to be in the range of 0.55 to 1.2 €/ kg depending on the outlet pressure. While hydrogen storage and transportation require substantial capital investment, their overall impact on levelized costs was found to be minimal compared to production and compression expenses, with storage costs averaging around 0.8 €/kg and transportation costs at approximately 0.0007 €/kg per kilometer. The same mathematical model was used to analyze two hydrogen utilization scenarios: fuel for fuel cell vehicles and feed for industry. Both pessimistic and optimistic cases were examined by varying cost-influencing parameters to predict the possible range of total levelized costs for the supply chain. The results showed that hydrogen as a fuel for fuel cell vehicles will stay more expensive than hydrogen as a feed for industry.

Hydrogen's competitiveness as a sustainable energy carrier depends greatly on its transportation and storage costs. Liquefying hydrogen for these purposes offers benefits like purity, versatility, and higher density. However, current industrial hydrogen liquefaction processes face efficiency and cost challenges, with a second-law efficiency below 25% and costs between 2.5-3.0 US$/kg_LH2, and they are mainly limited to small-scale. Scaling up liquefaction plants is a potential solution to reduce costs, but existing models often overlook the economic and technical viability of the conceptual plants.

Most reported liquefaction costs rely on "ballpark" estimation, hindering process economic comparisons between various processes. Industry-sponsored studies often use confidential data, limiting accessibility. Thus, this thesis aims to develop a comprehensive framework for modelling large-scale liquefaction processes and assessing their feasibility, focusing on the large-scale high-pressure hydrogen Claude-cycle liquefier concept.

The technical analysis focuses on the preliminary designs of main equipment, such as compressors, turboexpanders, and heat exchangers, ensuring compatibility with existing technology limitations. Aspen Process Economic Analyzer (APEA) is employed to estimate the capital and operating expenditure. At 0.1 €/kWh electricity price, the techno-economic assessment of the 125 tonnes per day (TPD) Claude-cycle concept yields specific liquefaction costs (SLC) of 1.55 €/kg_LH2. Sensitivity analysis shows electricity price has significant influence. Applying the established design approach, incorporating high-speed centrifugal compressors could reduce the SLC by 5.42% and potentially more.

Scaling up to 250 and 500 TPD shows potential SLC reductions of 7.80% and 9.45%, respectively, at electricity price of 0.1 €/kWh. Future projections suggest a potential 12.6% SLC reduction as the Claude-cycle liquefiers matures. In an ideal scenario, with incentives and low-cost renewable electricity, costs could range from 0.87 to 1.09 €/kg_LH2.

Finally, a cost-scaling curve for hydrogen liquefaction plants are estimated based on the cost results from this study. The curve is comparable to existing cost curves reported by industrial and government joint research projects, validating the methodologies developed in this thesis. Moreover, an experience curve is also predicted using cost data from this study and data found in the literature. The curve indicates a 17% price decrease in hydrogen liquefiers with each doubling of global liquefaction capacity.

Many of the high-performance portable electronics and electric vehicles (EVs) on the market depend on lithium-ion batteries (LIBs) as their primary energy source. If millions of EVs are to be manufactured each year, rigorous resource management for EV battery manufacturing, as well as a material- and energy efficient 3R system (reduce, re-use, recycle), will undoubtedly be required to assure the future sustainability of the automotive industry. Since lithium is only
found at a few locations around the world, there is an inherent danger from a geopolitical standpoint when it comes to accessibility. Political turmoil or instability in the nations controlling these lithium stockpiles may have a detrimental impact on world supply. Spent LIBs can be viewed as an alternative source of lithium. Considering that used LIBs contain toxic organic electrolytes and heavy metals, recycling them reduces resource waste and environmental contamination. Due to the difficulty of handling its complex composition and distribution, most recycling efforts and industrial processes focus solely on recycling the cathode and ignore the proper treatment of the aged electrolyte. Recovery of the electrolyte is crucial for achieving the legally mandated recycling efficiency set by the European Commission, as the electrolyte typically comprises of 10-15 wt% of a LIB cell. Therefore, this study explores the feasibility of
using crown ethers (12C4 and 15C5) to extract and recycle the lithium salt (LiPF6) from the electrolyte of spent LIBs. The extraction efficiency of these crown ethers is examined across various extraction conditions to identify the most favorable extraction condition. The results and findings obtained from the conducted experiments reveals that the extraction efficiency correlates with the mole ratio between crown ethers and lithium, up to a certain threshold (6:1 for 12C4 and 12:1 for 15C5) where further increase in mole ratio does not significantly enhance the extraction yield. The extraction yield displays an inverse relationship with temperature, indicating an exothermic extraction process that favors lower temperatures. Remarkably, varying the extraction time within the 5 to 30 min range exhibits negligible influence on extraction yield, suggesting rapid kinetics in the formation of the crown ether-lithium complex. Between the two crown ethers tested, 12C4 emerges as the more suitable option, achieving extraction yields of up to 60%. In contrast, the use of 15C5 necessitates larger quantities compared to 12C4 to achieve equivalent extraction yields. Consequently, using 15C5 not only increases the cost but also diminishes the overall process efficiency. Further research is proposed to conduct experiments for the extraction of the organic solvents in the electrolyte using CO2 and to develop methods for separating the extracted lithium from the crown ether without compromising the integrity of the crown ether, allowing for its reuse in subsequent extraction processes.