The objective of this study is to generate insights into the application of the reliability of a W2H system and its impact on the techno-economic performance. This involves examining the case of a single system to analyse on a micro-level the underlying conditions affecting performance, as well as exploring W2H farms to observe performance and the effects of changing conditions on a macro-level. To this end, MATLAB models have been utilised and developed to simulate various components of a system, such as wind turbines and electrolysers, focusing on aspects like hydrogen production and the number of breakdowns per year. The model creates insights into technical and economic parameters.

Renewable energy resources like wind and solar have the potential to revolutionize our energy infrastructure and enable a decarbonized society. The intermittent nature of renewables poses a challenge to ensuring a consistent and reliable electricity supply. Hydrogen technology is emerging as a promising solution for stabilizing renewable energy systems. There is still significant technological development required to cost-effectively integrate hydrogen with renewable energy assets. Conventional PV solar installations require power electronics for their operation, like charge controllers and inverters. Not only are these power electronic components costly and in high demand, but they also degrade faster than PV solar panels. Removing power electronic components could significantly lower the investment costs associated with a PV solar park.

This work focuses on how PV solar panels can be directly coupled to a modular alkaline electrolyzer, without grid-based buffering or the use of an inverter. Literature research revealed that hydrogen technology has seen little exploration in on-grid Hybrid Renewable Energy Systems (HRES) and no exploration in off-grid HRES. To appropriately investigate whether a directly-coupled HRES would be technically feasible, a megawatt-scale system was modelled and simulated. All elements of the HRES were modelled, duly accounting for physical limits and constraints. Components were sized and configured to complement one another, optimizing for maximum hydrogen production. To experimentally verify the validity of the proposed HRES, a 5 kW pilot system was constructed. To control the HRES, a new algorithm was developed using the Incremental Conductance maximum power point tracking algorithm as a basis. Within the new Maximum Hydrogen Production (MHP) algorithm, the step sizing was discretized and a variable step size was implemented which can be applied to any target slope. This allows for the system to target operational points which optimize hydrogen yield instead of electricity yield. Furthermore, the addition of tracking bias helped adjust for the asymmetric nature of the interaction between electrolyzer stacks and the PV solar park.

Simulation results in The Netherlands demonstrated that the feasibility of the HRES is dependent on the configuration of the PV solar park and on the number of electrolyzer stacks in the system. Compared to industrial and research benchmarks, the proposed HRES increased hydrogen production by 14.9% and 4.2%, respectively. Dynamic 'm-tracking' of the MHP algorithm goal increased hydrogen production by 0.8% in months of high irradiance. Months with a lower average irradiance experienced an artefact in the MHP algorithm, resulting in prolonged periods of zero power output. An experimental setup confirmed the simulation results, showing that it is possible to control a system of PV solar panels directly coupled to a modular alkaline electrolyzer. Experimental results revealed the need for moving average filtering to prevent fluctuations due to changing conditions of the electrolyzer and the weather from causing poor algorithm tracking ability. The low performance of the experimental setup can be attributed to a low iteration and measuring frequency, which increase the likelihood of a tracking error due to rapidly changing operating conditions. Economic analysis of the proposed HRES yielded an LCOH of €3.44 per kg, 20% and 13% lower than industrial and research benchmarks, respectively. Therefore, an HRES featuring PV solar and modular alkaline electrolysis is technologically and economically viable without the use of charge controllers and inverters.

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.

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.

Carbon sequestration involves the conversion of carbon dioxide gas into carbonates through reactions with magnesium or calcium bearing minerals, presenting a potential method to mitigate CO2 emissions and reduce their release into the atmosphere. This process can be classified into two categories: in-situ (subsurface) and ex-situ (surface). CO2 mineralization has demonstrated the ability to permanently store substantial quantities of CO2 without the need for extensive post-monitoring efforts, while also offering potential business model benefits for the generated end products. However, the field of mineralization still faces substantial technical and economic challenges, including high cost projections and slow carbonation kinetics, impeding further technological advancements in the field. Additionally, logistical challenges related to plant design and associated emissions contribute to the complexity of finding solutions to these problems.

In this particular study, the investigation focused on ex-situ carbon dioxide sequestration primarily through direct aqueous mineral carbonation, incorporating a direct air capture element. This approach was chosen due to the flexibility provided by direct air capture in terms of CO2 supply and the desirable characteristics of direct aqueous carbonation. Various models were developed using Aspen Plus software and compared, leading to the selection of the direct aqueous carbonation system as the optimal choice for CO2 carbonation. Further enhancements were implemented in the system, including recycled streams and heat integration, to reduce overall energy consumption. Optimization steps were also undertaken to determine the appropriate sizing of key equipment that make up the majority of the system's overall costs and to improve system efficiency.

An economic analysis was then performed, revealing that plant scales of 50 ktons/year yielded a positive Net Present Value (NPV), indicating profitability. Conversely, smaller-scale plants of 0.5 ktons/year and 5 ktons/year did not generate positive revenue, even with a high carbon credit price. This was followed by a sensitivity analysis that showcased the relevant parameters that holds significant effects on the economic performance of the system.

Moreover, business model cases were also explored, and it was concluded that utilizing the end products in building materials and road construction could potentially generate additional revenue for the mineralization system beyond storage options.

Overall, this investigation highlights the potential of ex-situ carbon sequestration through direct aqueous mineral carbonation, considering direct air capture, and emphasizes the importance of economic viability and revenue diversification in the successful implementation of mineralization systems to mitigate the effects of global warming.

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.

The steel making industry is highly energy intensive and a great contributor of greenhouse gas (GHG) emissions. It generated between 7% and 9% of direct emissions from the global use of fossil fuels in 2017 [1]. Gas emissions in an integrated steel mill (ISM) arise mainly from three streams: coke oven gas (COG), blast furnace gas (BFG) and basic oxygen furnace gas (BOFG).

This study focuses on the short term solutions to become a carbon neutral steelmaker where blast furnaces (BF) and basic oxygen furnaces (BOF) are still a fundamental part of the steel making process. The Rectisol® process is used to capture CO2 from the works arising gases (WAGs) of an ISM and to generate syngas which can be used as a chemical building block to produce liquid fuels among others.

The Rectisol® wash is a patented process by Air Liquide and Linde which uses chilled MeOH as a solvent. Both processes were first validated against stream data provided by the patents. PC-SAFT EOS was used to simulate the purification plant because of its strong theoretical foundation and its ability to adapt the parameters to predict component behaviour. Various binary interaction parameters proposed in literature were used to simulate the purification plants. From these simulations, it was found that the standard binary interaction parameters with the adjusted parameter for H2S-CH3OH, as proposed by Sun et al. [2], showed the best results.
The configurations of Air Liquide and Linde were used as base configuration to clean the feed stream. From these simulations, it was observed that in both configurations large portions of CO2 are lost in the stripping process of both configurations. Enhanced CCS configurations were investigated to increase the CO2 recovery of both configurations. The desorption of CO2 was altered by introducing multiple intermediate flashes to increase the desorption of CO2. Without optimisation, the downstream constraint for the CO2-rich stream of 95% CO2 content was almost met in the Linde configuration and requires further upgrading in the Air Liquide configuration. The decision was made to use the Linde enhanced CCS configuration as a base configuration since this would solely require a change in operating conditions to meet the downstream CO2 requirement of 95% content in the CO2-rich stream.

HCN and H2O require a seperate wash to avoid accumulation in the main wash. To treat these components together with H2S and COS, two pre-wash configurations combined with the Linde enhanced CCS configuration were looked into. A pre-wash configuration with a separate absorber column and dividing wall column (DWC) and a pre-wash configuration with a separate absorber column and rectifier with purge were examined. Both configurations meet the downstream requirements for the purified gas stream and CO2-rich stream. The main difference between the two configurations is the difference in thermal utility consumption and make-up MeOH. The decision was made to move forward with the pre-wash integrated configuration comprising of a rectifier and purge since additional make-up MeOH would be more cost-effective. The energy recovery method proposed by Linnhoff [3] was used to identify any potential energy saving of the purification plant. A heat exchanger network was designed which reduced the cooling duty by 57% to 54,9 MWth and the reboiler duty by 50,6% to 26,8 MWth. Finally, an economic evaluation was made of the final energy integrated configuration. Equivalent annual cost and operating expenditures of the purification plant were estimated at €12.32m and €51.13m respectively per year. This gives a cost per ton captured CO2 of €37,87.