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 global demand for ammonia is increasing. While traditionally driven by agriculture, new applications in sectors such as transport and energy are expanding the need for ammonia production. The conventional Haber-Bosch process, however, is highly energy-intensive and produces significant carbon emissions, making it increasingly unsuitable in light of growing climate goals. This study aims to take the first steps towards the development of an alternative ammonia production method based on lithium chemistry. To achieve this, two key reactions—lithium nitridation and the subsequent ammonia synthesis reaction—are closely investigated to establish proof of concept. In this investigation, a series of qualitative and quantitative experiments were conducted to evaluate the influence of key reaction variables, including time, pressure, and flow type. Additionally, a simplified shrinking core model was developed to quantitatively analyse reactant behaviour and inform process optimisation. The findings demonstrate that significant ammonia production is achievable under moderate conditions. At reaction conditions of 1.5 barg and 30°C, the lithium nitridation reaction reached up to 98% conversion within just 30 minutes. For ammonia synthesis, a peak concentration of 1 molar ammonia was achieved with a dissolution time of approximately 3.5 hours. The shrinking core model revealed a high initial reaction rate that gradually slowed, indicating the potential for optimising conversion efficiency relative to reaction time. Additionally, analysis showed that a slight increase in pressure positively affected conversion rates in the nitridation reaction. Overall, this lithium-based method offers a sustainable pathway for ammonia synthesis, producing heat and generating no direct carbon emissions. Incorporating heat recovery and reactant recycling could further strengthen the sustainability profile of this method, indicating that this approach could be implemented to cope with rising ammonia demand while reducing environmental impact.

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.

With increasing interest in developing green hydrogen infrastructure as a way to decarbonize the power, transportation and heating sector the storage of hydrogen becomes a crucial component. Although most present hydrogen storage techniques are of small-scale, the intermittent nature of renewable electricity and expected future green hydrogen production and consumption makes large-scale storage an important factor.
This study evaluates the techno-economic feasibility of storing hydrogen in an already-existing underground salt cavern, one of three large-scale gas storage systems. The work starts with an overview of the large-scale gas storage methods and the challenges associated with storing hydrogen. The current
existing salt cavern storage facility is discussed and is technically assessed for hydrogen storage. The investment and operating costs related to the hydrogen storage method were calculated using models developed, certain components of the model were modeled using Aspen simulation software, which was also used to calculate the cost associated with it. For various scenarios, the cost distribution and the Levelized Cost of Hydrogen Storage (LCHS) were estimated. Based on the outcomes, the LCHS ranged from a best case scenario of 0.34 e/kg to a worst case scenario of 1.94 e/kg. Sensitivity analysis was conducted for the various storage parameters, and based on the dominant component the Net Present Value(NPV) is assessed with an increased LCHS. To conclude the study an estimate for the electrolyser capacity required for the plant to operate continuously was determined.

This thesis presents a techno-economic analysis of integrating Concentrated Solar Power (CSP) and Solid Oxide Electrolysis (SOE) technologies for the production of hydrogen. The study begins with the development of system-level 0D models for CSP and SOE individually. These models are then combined to create a unified model for CSP-SOE integration. The Levelized Cost of Hydrogen (LCOH) is estimated and different modes of integration are explored, leading to the selection of off-grid integration as the preferred option. Sensitivity analyses are performed to assess the impact of various parameters on the system’s performance, and preliminary estimates indicate that a power capacity of 195 MW for CSP and SOE is required to achieve the desired hydrogen production target. Based on the results of the basic sizing analysis, a detailed plant model is constructed, incorporating the SOE and hydrogen processing sections. The Aspen simulation software is utilized for the implementation of these sections. To address the intermittent nature of renewable energy sources, three different strategies are proposed for operating the SOE system. After careful evaluation, a strategy is selected that yields an LCOH of $4.1 per kilogram of hydrogen, with a best-case scenario of $3 per kilogram and a worst-case scenario of $5 per kilogram. This study contributes to the understanding of the techno economic aspects of integrating CSP and SOE technologies for hydrogen production, highlighting the potential for achieving competitive costs and promoting the adoption of renewable energy-based hydrogen systems.

The transport sector remains one of the largest CO2 emitting sectors globally. Decarbonizing the transport sector is an important aspect in the energy transition. The word transition is key, since it will take several decades or more to transition to a fully sustainable world. During this transition mainly heavy-duty vehicles and probably most vehicles in third world countries will rely on liquid transportation fuels. Affordable and competitive biofuels are the way to fill this need in a sustainable way.

This study will focus on integrating several sustainable units and feedstocks to produce gasoline and diesel, starting with a pyrolysis oil feedstock. The integrated units consist of a gasifier, whose gasifying agent, oxygen, is produced by a SOEC electrolyser, running on renewable electricity. The syngas produced in the gasifier is produced during a low temperature Fischer Tropsch process over a cobalt catalyst. The aim is to choose operating conditions resulting in a large chain growth probability factor to produce heavier hydrocarbons chains, which can be refined to mainly yield diesel. The hydrogen required to upgrade the syngas formed in the gasifier is supplied by the SOEC electrolyser as well. The final upgrading of the produced crude oil is performed by separating the fractions in distillation columns and using a hydrocracker to raise the yield of the desired products. The end products are diesel and gasoline, meant to be blended in with gasoline and diesel from conventional oil refineries. The gasoline and diesel are sulfur free and especially the diesel is of high quality, due to tuning the process to predominantly produce paraffinic hydrocarbons.

The assessment of the process will be a techno-economic analysis based on a model made with Aspen plus. 5000 kg·hr-1 of bio-oil produced by BTG was converted to 990 kg·hr-1 of high-quality diesel and 557 kg·hr-1 of gasoline. The overall carbon conversion of the process to the end products was 57.6 %. By designing a heat exchanger network, optimizing the energy produced and needed by the heat sources and sinks respectively, an overall energy efficiency on LHV base of 57.2 % was reached. The process in the current day and age was found to not be profitable yet, but will definitely be in the future.

Ammonia (NH3) is a bulk commodity chemical known for its large production volumes and application in the global fertiliser industry, and is more recently being explored for its role as a sustainable energy vector. The industry standard ammonia production method is the century-old Haber-Bosch (HB) process, which is power by fossil fuels, and is accompanied with high energy intensity and large carbon-dioxide emissions. In this research, conceptual processes for the electrochemical synthesis of ammonia via the direct electrochemical nitrogen reduction reaction (e-NRR) from air and water were developed to assess their technical and economic viability compared to the HB benchmark. Different scales (91, 544 and 2055 t d-1) and electrolyzer cell configurations (alkaline electrolyzer (AEL), gas-diffusion electrode flow cell (GDE) and solid oxide electrolyzer (SOEL)) were considered. The results showed that small-scale production is more feasible for e-NRR NH3 synthesis due to the economies of scale of the HB benchmark. Among different electrolyzer types, the gas-diffusion electrode flow cell was found to be the most practical and economical for e-NRR NH3 synthesis. A sensitivity analysis showed that the electricity price is the most important parameter for the feasibility of e-NRR, and should ideally be as low as possible. Performance parameters of the electrolyzer, such as stack cost, operational current density, and faradaic efficiency, were optimized for minimal NH3 production cost, but were challenging to estimate due to the early stage of e-NRR technology. An optimized case was presented that demonstrated e-NRR NH3 can reach HB-parity, but the validity of the optimised parameters was difficult. It is advised that reliable laboratory-scale demonstrations are needed for an accurate assessment of the commercial feasibility of electrochemical NH3 synthesis.

There is an increase in the amount of CO2 emissions in the past few decades and the process of capturing it back is at a much lower rate. The need of the hour is to reduce the emission rate or even avoid producing them in certain aspects. There is a transition towards renewable energy sources
that could help us maintain the balance required. Hydrogen is one of the energy sources that are at the forefront of this transition in the manufacturing and automotive industry, but without sustainable methods for producing hydrogen, it would not be a great alternative to existing energy sources like
fossil fuels. Presently the most used method for hydrogen production is steam methane reforming from natural gas, which produces a significant amount of CO2 during the process and needs to be captured which reduces the efficiency and thus higher energy requirements. To tackle the existing
problems of CO2 emissions and help in the transition towards sustainable hydrogen is the main goal of this study. The project focuses on producing low-emission CO2 hydrogen from natural gas and biomethane by using a process called methane pyrolysis, an innovative process that does not produce
any GHG emissions during the process, the produced hydrogen is called Turquoise Hydrogen. Here the study focuses on different types of hydrogen production methods and different methods within methane pyrolysis. This research helped in understanding and choosing the right type of methane
pyrolysis method for further study and analyzing its process and economic advantages over traditional methods like the steam methane reforming process.

Low-carbon hydrogen is expected to have a large role in future energy systems. Recent research shows the short-term financial feasibility of blue hydrogen is often higher than green hydrogen. Ammonia production is particularly carbon-intensive due to its hydrogen production routes. This research focuses on the physics-based modelling of blue hydrogen production for ammonia synthesis, examining the influences of varying input conditions and economic scenarios on process performance and economics. Future energy systems will rely on flexible integrated solutions, emphasizing the importance of understanding how system parameters respond to diverse input conditions.

The ammonia plant consists of a desulphurization unit, a pre-reformer, an ATR, two water gas shift reactors, a physical absorption tower for CCS, a PSA for H2 purification and a Haber-Bosch ammonia synthesis reactor. Auxiliary components consist of heat exchangers, compressors and dehydration units. The modelling efforts focus on medium-fidelity models, reflecting the main thermodynamics and kinetics through first-order differentials assuming reactor simplifications. The plant simulations are based on plant operation in the Netherlands in 2030 under the following price assumptions: C_NH3= 0.472 €/kgNH3, C_elec= 41.77 €/MWh, C_NG= 22.64 €/MWh, C_CO2−tax= 0.135 €/kgCO2(eq), C_CCS= 0.05 €/kgCO2.

Each reactor model was separately validated through industrial data. Then the operational window was selected based on individual reactor limitations and the overall system chain performance: α=0.6, β=2.0, Tin=873.15K, Pin=2.8MPa. α and Tin are the most influential parameters from an economic and environmental perspective, showing the largest influence on levelized costs and emissions. Overall, under the simulated conditions, blue ammonia results in an 85% direct emission reduction compared to grey ammonia. The levelized costs of blue ammonia amount to 0.417€/kg and the NPV is 104 MEUR, the most influential economic parameters are the natural gas price and the ammonia selling price.

Three case studies were conducted in which specific economic and operational conditions were compared. Simulations of three IEA policy scenarios for 2030 show that the overall cost reduction in more sustainable scenarios is mainly driven by the lower natural gas price. Carbon taxes have a limited effect on the price of blue ammonia however do significantly increase the price of grey hydrogen compared to blue (a 0.11-0.17 €/kg difference). This results in a minimum 0.05 €/kgNH3 margin for the capture process costs in the stated scenario (0.09 €/kgCO2(eq) ), the other scenarios give a larger margin. Green ammonia gives a levelized cost of 0.457 €/kg NH3 under the same economic assumptions. The NPV is -480 MEUR, which is most affected by the electricity price and ammonia price. This research yields a 9% LCOA increase for green ammonia when compared to blue. The evolution of electricity prices is paramount in the financial competitiveness of green ammonia, more so than the CAPEX
evolution. The indirect emission intensity of green ammonia is lower than blue ammonia in the simulated conditions. However, this depends on the electricity source. Through carbon taxes blue and green ammonia can become cost-competitive to grey however this comes at a cost for the everyday consumer.
A simulation with dynamic operation yielded that inputting NG feed following seasonal natural gas pricing is not cost-effective when compared to steady-state production at the same seasonal pricing, even for +/-44% price fluctuations. The additional CAPEX costs for storage and larger process units are not sufficiently compensated by the lower variable OPEX costs. Further research should focus on
shorter-term supply and demand matching.

Overall, it can be concluded that this model can sufficiently simulate a blue hydrogen chain and be used for further simulation cases, also with alternative economic and operational assumptions. The technical parameters that affect blue ammonia production most are α and Tin. Economically the ammonia and the natural gas price are most influential. In comparison with grey and green ammonia, under the simulated conditions, blue hydrogen is the most cost-effective. Finally, the economic incentives through the seasonality of natural gas prices do not justify a dynamic operation of the process plant.

Due to financial and environmental benefits, the interest in high-temperature heat pumps, producing heat sinks above 100 °C, is rising. Research is intensifying, and technology is developing fast. However, of all the components of the heat pump cycle, the oil management system seems to be the least investigated, even though 12% of the faults in large-scale heat pumps are related to oil management. This study aims to develop a method that predicts the oil-refrigerant separation performance in high-temperature heat pumps.

Oil injection is necessary for high-temperature heat pumps to run without failures. The oil lubricates, seals and cools the compressor, increasing its performance and lifetime. However, if the oil is not separated correctly, it causes problems in the other components; The oil increases the pressure drop and decreases the heat transfer of the heat exchanger. Additionally, the refrigerant
partially dissolves in the oil, altering its thermophysical properties and increasing the risk of improper lubrication. Finally, the transport of the refrigerant deteriorates.

The oil management of a heat pump includes several components; an oil injector, oil separator, oil pump, oil sump/reservoir, oil temperature regulator and an oil filter. The core of oil management is the oil separator; three types of separation mechanisms are distinguished: impingement, centrifugal and coalescence. A centrifugal-type separator is most applied for industrial applications since it provides a wide operating range, allows high flow rates, and is simple and, thus, cheap to manufacture.

A data set containing the flow conditions and thermophysical properties is developed to use as input for the oil-refrigerant separation process modelling. A Daniel plot and developed correlations determine the properties of the oil-refrigerant mixture. The Tatterson equation is used to predict droplet size, and
the droplet distribution is described using the Rosin-Rammler distribution. A test case is designed to validate the developed method.

Finally, the oil separation due to a cyclone oil separator is modelled in Ansys fluent. A transient simulation based on the Reynolds stress modelling approach is conducted for the continuous phase. The discrete phase method simulates the oil-refrigerant droplets. The developed method serves as a strong foundation for future research. For the future, including models for droplet behaviour and wall-film models is strongly recommended to provide scientifically relevant outcomes.

The nitrogen crisis is one of the biggest problems in society. Therefore, a tremendous amount of research is going on to solve this problem. This thesis focuses on solving the problem of nitrogenous emissions by capturing ammonium emissions from agricultural farms. Biochars have been gaining much attention due to their desirable properties, such as large specific surface area, a robust pore structure, and the presence of rich functional groups like carboxylic, phenolic, hydroxyl, hydroxylic, and metals. All these properties help biochar
in adsorbing nitrogenous products. Biochars can also serve as good soil conditioners when returned to the soil. The application of biochar to the ground could also increase soil fertility. Research has shown promising results
in applying biochar for ammonium capture at a lower price. Ammonium adsorption experiments were carried out to quantify the amount of ammonium adsorbed on biochars. Further, various experiments were carried
out to characterize the biochar for ammonium adsorption, such as X-ray diffraction (XRD), X-ray fluorescence (XRF), Brunauer-Emmett-Teller (BET) surface analysis, FTIR (Fourier Transform Infrared Spectroscopy). In addition, the adsorption mechanism was determined by analyzing the physico-chemical properties of pine wood pellet biochar and its UV activated biochar, the mechanism was also determined for plum tree wood chip biochar and its UV activated biochar. Based on the analysis, it was found that the adsorption of ammonium on biochar is mainly because of ion exchange due to the presence of metals and functional groups. Through adsorption experiments it was found that, biochar 2, made of plum woodchip, has a higher affinity for capturing ammonium
over biochar 1 made of pine tree wood pellet because of the presence of metals and inorganic compounds on top of the surface. UV activation affect biochar’s adsorption capacity towards ammonium. Biochar 2 UV, after activating, has the highest adsorption capacity among all four biochars because of an increase in principle bulk elements like carbon. Apart from the characterization, calculations were made to find out the amount of biochar required to capture current ammonia emissions; this economic evaluation shown commercial feasibility of the
project

The unprecedented increase in mean ambient temperature due to immoderate CO2 emissions has shifted the energy policy towards the replacement of fossil fuels with renewable energy sources. Nevertheless, the intermittency of these technologies renders them unsuitable for reliable energy supply. A prominent solution is the utilization of renewable energy to produce green hydrogen that can be stored for later use.

The most environmental-friendly viable method for green hydrogen production is the electrolysis of water. Between the already existing types, alkaline electrolyser is the one with the highest technological maturity and lowest cost of hydrogen production. Despite that, the low energy efficiency, and the energy losses associated with the materials and the geometrical configuration make it difficult to produce hydrogen at competitive prices compared to fossil fuels. The connection with renewables exposes the electrolyser to variable loads that negatively affect the life of materials and the purity of hydrogen since the operating conditions like temperature and electrical current change constantly. Previous research work has shown that the energy losses owing to the electrode kinetics, diaphragm, and electrolyte resistivity are responsible for higher energy consumption than the thermodynamic minimum. These losses are a strong function of temperature and current density. This research project aims to investigate the performance of the electrolyser under fluctuating working conditions to get an insight into how energy consumption and efficiency are affected.

The research objectives are encountered by building a physical model that accurately predicts the electrochemical behavior of the cell under various circumstances and simulates the thermal response of the electrolyser. The numerous experiments performed at XINTC’s laboratory enabled the improvement of the model’s accuracy and the consideration of effects that are not easily confronted in a purely theoretical investigation. The results showed that the model accurately describes the experimental data of the cell with less than a 2% discrepancy. The model was also used for simulating the cell behavior under different pressures, electrodes, and diaphragm materials. The elevated temperatures and highly electroactive materials such as Nickel significantly reduce the voltage of the cell. Regarding the thermal model of the theoretical electrolysis system, sensitivity analysis of the current density, ambient conditions, and electrolyte flow was performed. The temperature across the system was uniform at an electrolyte volume flow of 5 Lt/min and the cooling load accounted for 20% of the electrolyser power. The thermal modeling of the real experimental setup was successful (<1.5°C deviation) at high current densities indicating the sound assumptions of the model. On the contrary, at low current densities, the discrepancy between the model and the experiments reached 10% due to the additional heat generation induced by the shunt currents. For that reason, a simplified electrical circuit analysis was formulated and included in the model. This led to reducing the deviation to less than 5% and at the same time calculation of the current efficiency in the absence of measuring devices was achieved.