Today’s day-to-day essentials like packaging, cosmetics, medicines, fertilisers, detergents and paints are made primarily from fossil-based raw materials such as crude oil or natural gas. To reach the ambitious CO2 emission reduction targets needed to mitigate climate change, replacing the use of fossil-based feedstocks with sustainable carbon feedstocks (i.e. defossilisation) will be vital. In today’s petrochemical industry, fossil-based raw materials are first broken down into chemical building blocks (CBB) which are the backbone of the chemical sector. The CBB production can be defossilised by using alternative carbon sources (ACS) such as CO2, biomass and plastic waste as feedstocks. However, changing the feedstock to produce CBB is not just limited to changing a given technology, as CBB are generally produced in highly interconnected petrochemical clusters. Thus, changes in feedstock can result in ripple effects along the interconnected value chains. Identifying and quantifying such ripple effects at process and cluster levels were the focus of this dissertation. The research highlights that ACS feedstock limitation will play a key role in how industrial clusters will develop. The work in this thesis shows that there is no single “silver bullet” process to defossilise the production of CBB, but a combination of ACS and fossil-based technologies will be required due to the magnitude of energy and material required for such a change.

Climate change, driven by increased greenhouse gas emissions from fossil fuels, is a critical global challenge. The Netherlands aims for a 55% CO2 reduction by 2030, with the Port of Rotterdam as a significant emitter. Renewable methanol production from biomass offers a promising solution to reduce these emissions significantly. This thesis aims to study the techno-economic trade-offs and synergies of CO2 compared to H2 syngas conditioning for a biomass-based methanol plant. Syngas produced through biomass gasification typically lacks the adequate stoichiometric ratio for methanol production, requiring a conditioning step. The conventional WGS approach, while increasing hydrogen content, also increases CO2 production, leading to higher costs and reduced efficiency. Carbon removal further limits efficiency and methanol production. While H2 syngas conditioning routes and synthesis have been extensively investigated, other approaches like RWGS and CO2 -co-electrolysis require further study. The configurations are assessed employing process simulations from Aspen Plus, which were developed using data from the literature. The gasifier was modelled and validated using the IGT experimental data. OLGA and Rectisol were employed for syngas cleaning. Similarly, four syngas conditioning configurations were modelled: water electrolysis, WGS, RWGS and CO2 co-electrolysis. The conditioned syngas compositions for each configuration were used in a separate isothermal methanol reactor model, including purification. CO2 co-electrolysis and RWGS configurations showed the highest biomass utilisation efficiency, but required significant energy input. Water electrolysis had moderate efficiency and the best environmental performance with nearly zero direct CO2 emissions. WGS was the least efficient and had the highest CO2 emissions. This was primarily due to the separation of CO2. Economically, all options were less competitive than market methanol prices. CO2 coelectrolysis had the lowest levelized methanol (LCOM) cost at €2.39/kg, followed by water electrolysis at €2.42/kg and RWGS at €2.63/kg. WGS performed worst at €3.55/kg. The study reveals that RWGS and water electrolysis configurations demonstrate the lowest CO2 emissions, making them ideal for scenarios where reducing the carbon footprint is a priority, primarily when electricity is sourced from low-cost, renewable energy. CO2 co-electrolysis, while achieving high biomass utilisation efficiency and the lowest LCOM does not have the lowest CO2 emissions due to its reliance on natural gas for heating. Conversely, the WGS configuration, although minimising electricity consumption at 0.60 kWh/kg MeOH, is the least efficient overall, with high CO2 emissions and the highest LCOM. CO2 co-electrolysis and RWGS are more suitable in scenarios where high biomass utilisation and competitive costs are prioritised and where electricity prices are stable or low. The WGS process may be more suitable for high electricity costs, and minimising capital expenditure is crucial. In conclusion, this study presents valuable insights into the techno-economic synergies and trade-offs of syngas upgrading through CO2 conditioning compared to hydrogen conditioning for methanol production from biomass gasification. Addressing the identified challenges and leveraging the synergies can advance towards a more sustainable and economically viable methanol production industry. Future optimisation and validation efforts will be essential for translating these findings into practical, scalable solutions.

The electrification of the production processes in the chemical industry is seen as a promising option to reduce its greenhouse gas emissions. This would result in a significant increase in the demand for electrical energy. The supply of electricity is becoming more fluctuating due to the variable nature of solar and wind energy. To ensure the stability of the grid, the consumption of electricity needs to equal the supply. Additionally, many countries are dealing with grid congestion, which means that there is insufficient transmission capacity for all consumers who want to receive power. One potential solution to these challenges is industrial demand response whereby companies adjust their electricity consumption to the available supply. The chemical industry might be able to provide this demand response through flexible operations of its production processes.
The goal of this research was to investigate whether companies have concrete plans to engage in energy flexibility with their production processes, and to determine the priority level they assign to it. This included examining how widely energy flexibility is incorporated into companies’ ten-year roadmaps, identifying the obstacles to electrification in the chemical industry, and understanding the challenges of operating chemical production flexibly.
To answer these questions, interviews were conducted with participants who work at chemical companies in the Netherlands. The participants were recruited by compiling a list of all chemical companies in the Netherlands and using LinkedIn to approach suitable candidates within each company with a request for an interview. Those participants who responded positively were interviewed using a semi-structured interview methodology in interviews lasting 30-45 minutes. The interviews were processed into anonymous summaries which were then used to answer the research questions.
Participants from twelve different companies were interviewed, representing approximately a quarter of all companies active in the Dutch chemical industry. These companies are active in a mix of sub-sectors of the chemical industry. A possible response bias should be noted, as companies already engaged in electrification and energy flexibility may be over-represented among these twelve companies compared to the chemical industry as a whole. Moreover, as only one participants was interviewed per company, there is a significant chance of personal bias affecting the results.
The results showed that flexible energy use was included in half of the twelve interviewed companies. However, it was a priority for only two companies. For the remaining four companies, flexible energy use was a side benefit of using both natural gas as well as electricity as a source for process heat in the transition to fully electrified process heat generation. Although four more companies had tentative plans for flexibility, they did not expect these to be feasible within the next ten years.
The results also showed that for eight out of twelve companies, lack of sufficient grid capacity was a crucial obstacle to electrification. However, only two of those companies indicated that they would be willing to consider operating their process flexibly in return for accelerated access to the desired grid capacity. The benefits of quicker access to the grid do not outweigh the obstacles to operating flexibly for most companies. The most important obstacles were related to the high investment cost of chemical plants in the chemical industry. At this juncture, the financial benefits of demand response do not outweigh the increased investments costs needed to make flexibility possible for most companies.

In 2021, the EU set a goal for climate neutrality by 2050, followed by a 2024 recommendation for a 90% reduction in net greenhouse gas (GHG) emissions by 2040 compared to 1990 levels. According to the 2022 IPCC Sixth Assessment Report, achieving the 1.5°C goal is still possible but requires immediate and significant changes across all sectors.

The chemical industry, responsible for 10% of industrial CO2 emissions in 2022, must accelerate its shift away from fossil fuels. This involves replacing fossil-based fuels and feedstocks with alternatives that have lower environmental impacts, such as using CO2 captured from the air or industrial emissions and renewable energy sources like solar, wind, and geothermal. This shift has led to the development of carbon capture and utilization powered by intermittent renewable electricity (IRE).

However, electrochemical processes struggle with fluctuating electricity supplies. Variability in electricity can lower production rates or damage electrolysers. Managing these fluctuations to maintain steady production is difficult with control systems alone, emphasizing the need for flexible operation in electrochemical plants.

Feasibility studies are essential for understanding the market competitiveness of new technologies, identifying potential technical, investment, and environmental challenges.

Electrochemical processes using renewable electricity to produce chemicals are gaining traction. While industrial-scale water electrolysis has been widely studied, less research has focused on electrosynthesis under intermittent electricity supply. This dissertation explores process designs and conditions for scaling up a novel CO2 electrochemical plant using intermittent renewable electricity. The research addresses three sub-questions:

What does flexibility mean in designing novel chemical processes?
How does intermittency affect the techno-economic and environmental performance of a novel CO2 electrochemical plant?
What factors influence the competitiveness of novel CO2 electrochemical technology?

For the first sub-question, a systematic literature review on flexibility was conducted, resulting in a conceptual framework for defining, designing, and evaluating flexibility in novel chemical processes.

For the second sub-question, a microbial electrosynthesis (MES) plant producing hexanoic acid from CO2 was designed and modeled in Aspen Plus. The plant's volume flexibility was explored by varying throughput rates. The plant was coupled with IRE profiles and buffering units using Python scripts, and optimization was performed to enhance economic potential. The study assessed how intermittency impacted the plant’s performance and carbon footprint.

For the third sub-question, the techno-economic and environmental performances of hexanoic acid from MES were compared to its competitors. Two future value chains were considered: one producing hexanoic acid and another upgrading it to n-alkanes for sustainable aviation fuel (SAF). Competitors included plant-based and fermentative hexanoic acid, and certified SAFs.

Technical findings indicate that improving electrolysers’ productivity and product concentration is crucial. Inflexibility in downstream processing (DSP) technologies can affect production and economic outcomes. Designing flexible DSP technologies and sizing equipment to handle fluctuations is essential. Buffering units can mitigate intermittency impacts, and smaller parallel units can maintain production during low electricity supply.

Economic findings suggest that novel electrochemical plants driven by constant grid electricity might struggle in today’s market due to high CAPEX and electricity costs. Intermittency worsens this issue. Enhancing technology, securing cheaper electricity, and optimizing buffering units can improve economic outcomes. Future market conditions and demand shifts could also impact competitiveness.

Environmental findings show that combining electrolysis with renewable electricity has lower impacts than using grid electricity but might not be cleaner than competitors. DSP-related utilities and chemicals can be environmental bottlenecks, linked to selected DSP technologies and CO2 feedstock's carbon intensity.

This dissertation provides an ex-ante assessment of novel technology, acknowledging limitations such as not considering ramping rates. Future research should explore more flexible DSP technologies, modular units, and interactions between different flexibility types. Upgrading hexanoic acid to n-alkanes is currently unattractive environmentally; alternative products like adipic acid could be considered.

Joint efforts between the industrial sector and power suppliers are necessary for significant defossilisation through electricity-based chemical processes.

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.

The European Union has set out to become carbon neutral by 2050. To reach this goal, the fossil-fuel-dominated energy system must be transformed into a low-carbon renewable-based energy system. One method proposed to reduce fossil-fuel dependence is to establish a renewable hydrogen supply chain between Africa and the European Union. This work provides a model framework that enables an economic analysis of a renewable hydrogen supply chain between northern Africa and the EU. The aim of this work is to gain a better understanding of large-scale intercontinental renewable hydrogen production by investigating the factors that impact the economic performance of this system.
A mixed-integer linear programming model that describes the supply chain is built, and modeled in Python and a case study defining the overall energy system under consideration and applied to this model. The system must provide 780 TWh of hydrogen demand for the EU in 2050. Hydrogen is produced by water electrolysis, using renewable electricity from solar photovoltaics. The water required for electrolysis is supplied through reverse osmosis of seawater. Seasonal storage of hydrogen is enabled through the inclusion of hydrogen storage in salt caverns.

The resulting annual costs of operating the supply chain are 36.55 B$, corresponding to a levelized cost of hydrogen of 1.56 $kg^-1. The main contributors to the cost of the supply chain are solar photovoltaics (50\%), alkaline electrolysis (22%), and transportation (26%). Through a sensitivity analysis on price uncertainty, it is found that the system is most sensitive to photovoltaics prices (59%), electrolysis prices (21%), and hydrogen pipeline prices (18%). A sensitivity analysis of the interest rate on capital investment points towards a significant impact of the interest rate on the total annual cost.

The findings of the model and applied case study in this work are then compared to projected costs in other works. From this analysis, it is found that hydrogen production using electrolysis will be cheaper than fossil-based low-carbon hydrogen production alternatives in the form of steam methane reforming or coal gasification with carbon capture technology. Predictions of the selected works regarding electrolysis-based hydrogen production using renewable electricity show an expected LCOH of between 1.66 - 2.39 $kg^-1.

This work indicates that a renewable hydrogen supply chain between Morocco and the EU in 2050 is both technically and economically feasible, able to compete with alternative hydrogen production methods, and able to supply 35% of the projected hydrogen demand. Moreover, this work developed a general hydrogen supply-chain model that allows for the implementation of additional features as well as the analysis of different case studies through the adjustment of case-specific parameters.

As global climate change concerns intensify, the search for renewable-based alternatives to products and processes that rely on fossil fuels becomes ever more important. A process that has been championed is the co-electrolysis of carbon dioxide and water, under the supply of renewable energy, via high-temperature solid oxide electrolyser systems. The technological combination can produce syngas directly. This syngas is a renewable-based alternative to fossil-based syngas, which has a widely established market and can directly be used for the generation of energy in power plants, or as a precursor for the production of carbon-based chemicals and fuels. Although many technology-specific improvements have been made in recent years that contributed to the creation of a promising outlook and an increasing number of demonstration projects, the feasibility and implications of implementing the process on an industrial scale remain largely unaddressed. Since many technologies fail in the transition from benchtop to industrial scale, a deeper understanding of the requirements that are opposed at an industrial scale should be obtained, to this end, this work applies an exploratory research approach to investigate the feasibility and opportunities of the supply chain that supports the production of syngas via co-electrolysis. To delineate the feasibility of the supply chain, this work considers two perspectives of feasibility; (i) the feasibility of the horizontal supply chain which encompasses the requirements and availability of feedstocks, technology and process scales, and market potential, and (ii) the feasibility of the vertical supply chain which encompasses the availability of materials required for the operation of solid oxide electrolyser systems. To investigate the opportunities of the supply chain, this work considers decentralised and centralised supply chain configurations. To initiate the research the individual supply chain units that are required for the process to be operatable at industrial scales were assessed. The requirements and scales of the individual units are matched with the current and expected future scales of technologies, feedstocks and markets. From this scale match, it can be concluded that based on feedstock availability and syngas market size, it is technically feasible to completely replace fossil-based syngas with renewable-based syngas produced by solid oxide electrolyser technology. However, several aspects such as the renewable energy requirements and the number of high-temperature solid oxide electrolyser systems that are required, impose practical limitations on the large-scale rollout. The influence of these practical limitations is aggravated after an assessment of the opportunities of decentralised and centralised supply chains, as both possibilities require capital investments on the scale of 1 Billion Euros and no positive return. A smaller implementation scale was also considered, and the limitations opposed to such a scale, seem much easier to overcome, highlighting potential future research directions. To delineate the feasibility from the vertical supply chain perspective, the material requirements of solid oxide electrolyser systems and the corresponding material availability were investigated. From this investigation, it can be concluded that from a global point of view, only Gadolinium opposes feasibility limitations. However, from a European point of view, the limitations seem much more severe. Based on the findings of this work, future research should focus on detailed analyses of the potential of solid oxide electrolyser supply chains at smaller scales, as there exist many opportunities that could improve overall supply chain performance, and smaller scales oppose less severe problems.