Capturing and utilizing the emissions of CO₂ has become a method to reduce the occurring emissions from industrial flue gases. One of the methodologies to capture and use the CO₂ is through the CO₂ capture and reduction (CCR) process. This process uses a bi-functional catalyst to capture CO₂ from diluted gas streams and subsequently reduce it to CO in the presence of H₂. The obtained product (syngas) can be further used as feedstock in for example the Fischer-Tropsch process. To implement a novel technology in industry, the
technology itself should be economical feasible.

To determine the feasibility of the process a technoeconomical analysis is executed. The analysis uses process parameters obtained by evaluating the catalytic activity of the bifunctional catalysts. Two catalytic
systems have been evaluated: Cu-K/𝛾-Al₂O₃ and FeCrCuK/PMG20. Effect on the synthesis conditions of Cu-K/𝛾-Al₂O₃ were also investigated. Cu-K/𝛾-Al₂O₃
without additional drying steps during the synthesis shows a higher CO₂ capacity and a faster CO production rate compared to the other catalysts. Furthermore, to
estimate the H₂ requirement in an industrialized process the consumption of H2 during the process has been quantified.

To ensure a continuous process operation, a two reactor process has been proposed in the techno-economical analysis. The sizing and subsequent cost of the process equipment has been determined by utilizing the obtained process parameters. Besides the capital costs, the operating costs were also estimated to determine the profitability of the process. After the monetary benefit of selling the syngas was determined, it could be stated that the process is profitable under certain conditions. The process is profitable if the used H₂ source has a buying price below $1.8 per kilogram. If sales of allowances is possible, the buying price of H₂ needs to be below $2.4 to ensure a profitable process.

To reach the goals of the European Green Deal (CO2 emission reduction of 55% by 2030 and climate neutral by 2050), North-Western Europe has to import sustainable energy as locally produced renewable energy will not be sufficient to meet the total demand. This will be realised by importing green hydrogen from areas with a surplus of renewable energy. If those areas are in another continent, the hydrogen is expected to be imported by vessel and received and stored in a hydrogen import terminal. Since Gasunie has an LNG plant in the Port of Rotterdam that becomes available within a few years, they want to investigate the possibilities to retrofit this plant into a hydrogen import terminal.

This research has investigated if the current LNG-Peakshaver can be retrofitted to an LH2 import terminal. This import terminal will receive, store and process LH2 to be delivered to the hydrogen Backbone (future hydrogen grid in the Netherlands owned by Gasunie). The imported LH2 will be received from maritime vessels at conditions just above ambient pressure and below its boiling point (-253˚C). It will be stored in the retrofitted LNG storage tanks, and depending on the hydrogen demands of the grid, LH2 will be processed (regasified) to the requirements of the grid (5˚C and 50 bar). This send-out process is very similar to LNG and requires pumps, BOG compressors and evaporators as process equipment.

The differences in physical and chemical properties have been analysed to determine if retrofitting LNG process equipment into LH2 application is feasible. The three main property differences that most affect the processes at the terminal are 1. the lower temperature (-253˚C instead of -162˚C), 2. the lower density and 3. the lower latent heat of vaporization of LH2 as compared to LNG. In view of these differences, it has been established that the reuse of the current LNG equipment is not possible. Even the pipes cannot be reused, as the LH2 pipes must be vacuum insulated to prevent liquid oxygen formation at the outside of these pipes.

Enhanced research has been carried out into the required process equipment. For the LH2 pumps, cavitation and the low pressure-head of the centrifugal pump are a problem. To overcome these, a special inducer is used, and three HP pumps in series to reach the desired pressure of 50 bar. Regarding the hydrogen BOG compressors, a vertical labyrinth (reciprocating) type is considered. However, manufacturers cannot yet design compressors that operate at temperatures as low as -250˚C. For the evaporator, a Super-ORV design with seawater as the heat source is considered the best option to evaporate the LH2. This design is an enhanced ORV that improves the heat transfer, which is desirable considering the lower temperatures of LH2.

Retrofitting the LNG tank is essential since it is the most expensive part of the plant. The current inner tank material and insulation are not capable of handling LH2. Therefore, two solutions have been explored to retrofit the storage tank. The more expensive solution -resulting in a lower BOR- is implementing a new vacuum insulated storage tank inside the existing concrete construction. The other option is to attach membrane insulation panels at the inside of the current storage tank.

Simulations have been performed to analyse the desired terminal configuration with regard to energy efficiency. The differences in configuration depend on the tank's insulation method, BOG processing, and cold exergy utilization. From these results, it is concluded that a compressor that can handle temperatures as low as -250˚C is essential for an LH2 terminal as it dramatically improves energy efficiency. Considering the terminal configuration, it is concluded that a membrane insulated tank combined with a recondenser to process the BOG flow is the desired solution if the terminal has baseload send-out. However, when a low minimum flow is required, a vacuum insulated tank in combination with “cold” BOG compressors is the best solution. Both configurations have an energy efficiency loss for baseload send-out of 0,13% of the HHV. To determine the feasibility of the terminal configuration, a further cost-efficiency evaluation is essential, next to this energy efficiency analysis.

The overall conclusion is that for the storage tank, the most expensive part of the plant, potential solutions to retrofit it exists. Especially the membrane insulation method is very promising and deserves more in-depth research. However, reusing the LNG process equipment is not possible. The equipment for the LH2 process is not yet commercially available except for the LH2 pumps. Further research is recommended because an LH2 import terminal has many advantages over other hydrogen import terminals, namely a relatively simple and flexible send-out process that requires little energy input.

The global concern of the increasing levels of CO2 is growing quickly in the recent years. Therefore, a lot of research is currently underway with respect to closing the carbon cycle. The electrochemical reduction of CO2 is a promising technology that could help utilize the CO2 as a feedstock to produce chemicals and fuels, while storing the excess energy generated from renewable energy sources in chemical bonds. Due to its simplicity and economic feasibility, the conversion of CO2 to CO has a high potential in the industrial market. Membrane Electrode Assembly (MEA) is an interesting electrochemical reactor configuration to produce CO on industrial scale due to the low ohmic losses and reduced risk of catalyst poisoning. Optimizing the catalyst and operating conditions are key steps towards the commercialization of the process. This research focuses on understanding the influence of different process parameters on the CO selectivity while analyzing the performance challenges. Multiple inlet flow rates of CO2 were tested at different current densities to evaluate its impact on the faradaic efficiency. The experiments were performed using KOH-exchange MEA cell with gas diffusion electrodes and Sustainion membrane. Since the product of interest is CO, Ag-based catalyst layer was sputtered on the gas diffusion electrode. The cathodic products were identified and quantified using gas chromatograph. The experimental results have shown that increasing current density resulted in lower CO selectivity, while the inlet flow rate did not have a significant effect. It was also shown that the cell could not achieve higher than 200mA/cm2 due to the accumulation of salts blocking the gas flow channel.
On top of that, a simple 2D model was developed in COMSOL Multiphysics to understand the mass transport and concentration distribution in the gas flow channel. The model was not able to simulate the complexities of the electrochemical process and represented an ideal plug flow reactor. It is understood that the incorporation of reaction kinetics and current distribution is necessary to replicate the real scenario.

The total investments in the global energy system amounted to 1.85 trillion in 2018 [1]. Globally over 400 exajoule [2] was provided to energy consumers. The energy consumption is closely related to the emission of green house gasses [3] [4] [5]. In the Kyoto and Paris agreements the international community formalized the intention to reduce the emission of green house gasses in an effort to mitigate global warming [6] [7]. Economic progress has long been linked to increased energy consumption [8] [9]. Mitigation of green house gasses whilst facilitating economic growth poses one of the major challenge of the twenty first century [10] [11]. Development of climate policy and business strategy that facilitates both the mitigation of global warming and economic growth requires understanding of the energy market. In an effort to expand the understanding of the energy market we examine the historic effects of a country’s wealth on the country’s energy mix by applying a multinomial logit choice model for energy carriers to various sectors on a global scale. We find evidence for ordered wealth effects in sector categories Heavy Industry, Agriculture & Other Industry, Passenger Transport Rail, Freight Transport Rail, Residential Heating & Cooking, and Services.

This report aims to evaluate the feasibility of a small pilot plant placed near Broome, Australia to produce 3 tons of hydrogen per day using photovoltaic (PV) energy. Using PVsyst, a PV modelling software, the maximum power operating points were determined for a test layout. This was then transformed to other layouts which allowed the optimum layout to be found for a system connected to electrolyzers using maximum power point tracking technology. A second scenario using a battery was also modelled and optimized. Finally, the third scenario used direct coupling, meaning that the PV panels were not operated at their maximum power point but rather at where the electrolyzer and PV current and voltage lines crossed. This resulted in a lower power yield but also lower costs. To find the current and voltage curve for the PV field, the data from PVsyst analyzed to find the short circuit current and the open circuit voltage. This allowed the full current and voltage curve to be determined, which allowed the intersection point with the (experimental) electrolyzer current and voltage curve to be determined.

In all simulations piping storage was used to remove the intermittency of the hydrogen production by having a capacity of 3 tons of gaseous H2. This ensures a constant stream of hydrogen to the liquefaction system.

Using preliminary results an electrolyzer degradation simulation was carried out, to find how the electrolyzer would behave after 20 years of use. Although the influence of intermittency could not be found in literature, it was shown that the electrolyzer produces, on average during its 20 year lifetime, approximately 5.7% less hydrogen than it would without any degradation. This has been included in all financial analyses carried out in this report, along with a 7% weighted average cost of capital.

The financial framework has been based off of a number of different sources and forecasts. Due to the limitations of publicly available data some forecasts were replaced with constant prices which do not evolve throughout the years.

Using the hydrogen production models and financial frameworks it is possible to compare the different scenarios. From this a price of 4.16$/kg was found for a MPP coupled system, 4.39$/kg for a MPP coupled system including a battery, and 4.02$/kg for a direct coupled system. The third scenario was furthermore looked at in terms of physical layout; it was found that the decentralized layout consisting of smaller subplots was slightly more expensive than the standard centralized layout (4.09$/kg). For this pilot plant it is advised to use a decentralized topology, combined with a decentralized layout consisting of multiple smaller plots. Although the centralized layout is slightly cheaper, it contains more system critical components which could cause a large portion of the system to be inactive if they are broken.