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.

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.

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$/kgLH2, 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 €/kgLH2. 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 €/kgLH2. 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 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.

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.

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.

Meeting the ever-increasing energy demands in our planet where conventional sources of energy are finite and fast depleting, controlling adverse phenomena like climate change, soil erosion, greenhouse gas emission, ozone layer thinning and pollution will remain profound challenges until widespread adoption of sustainable sources of energy is achieved. The shift to a sustainable energy system cannot be complete without the contribution of biomass energy. Within the ecosystem of biomass energy, gasification is a thermochemical conversion process undertaken to obtain a high-quality product gas by increasing the low energy density of solid biomass. The product gas can be used in power applications or be converted to liquid fuels for transportation. Gasification is carried out at high temperatures (700-1500°C) by using a gaseous agent under sub stoichiometric conditions (R.A. Kersten & De Jong, 2015). The main non-condensable permanent gases obtained from gasification are CO, H2, CO2 and CH4. Use of allothermal gasifiers, whose working is based on the separation of combustion and gasification chambers within the gasifier, with heat supply for carrying out endothermic reactions, established via heat carrier or heat exchanger, have shown many advantages compared to the conventional gasifiers (Hofbauer & Materazzi, 2019). The mix-up of product gas and flue gas is avoided in this type of gasification. Secondly, while using air for biomass combustion, the nitrogen present in air reduces the quality of the end product by not participating in gasification, thus resulting in a diluted product gas. A high-quality product gas can be obtained from allothermal gasifiers without the need for establishing an expensive air separation unit, as required in case of conventional gasifiers. The 50 kWth Indirectly Heated Bubbling Fluidized Bed Steam Reformer (IHBFBSR) at Delft University of Technology (TU Delft) represents a new concept of allothermal gasification technology where heat required for the endothermic gasification reactions is provided by two radiant tube burners placed vertically inside the reactor, one at the top and one at the bottom. The aim of this research is to optimize and validate the kinetic model developed for the IHBFBSR by a former student, Maarten Kwakkenbos in Aspen Plus®. The optimization is carried out with the help of the several steps, described in the report. The optimized model is then validated by using the results of the gasification tests performed under various operational conditions by PhD Candidates Mara del Grosso and Christos Tsekos. The optimized model predicts the gas composition obtained from the IHBFBSR quite well. In addition to the yield of permanent gases, N2, H2O and tars concentration in the product gas, along with various gas ratios (CO/H2, CH4/H2, CO/CO2) from the model are compared with the experimental values and found to be in reasonable agreement. Moreover, key performance indicators such as carbon conversion (CC), cold gas efficiency (CGE) and overall efficiency (OE) are also evaluated from both model and experiments and compared. The error ranges for most of the parameters lie within the reported deviations observed in various gasifier models in literature. After the validation of the model, the possibility of recycling a fraction of the product gas to feed the burners in order to make the set up more sustainable is evaluated. Sensitivity analyses is performed by varying steam to biomass ratios (SB*), primary and secondary air flowrate to evaluate the best process conditions under which product gas obtained from the gasifier, after subsequent cleaning, can be used for methanol production based on the H2/CO ratio. The results indicate that a higher SB* and a higher secondary air flowrate can result in a H2/CO ratio closer to the desired value required for optimum methanol production. From the heat analysis performed for the model, a possibility of increasing the overall efficiency of the process by adding a bypass line in the gasifier setup is suggested to be explored. The master thesis concludes by answering the research questions and recommendations to improve the detailing and accuracy of the model.

This report provides a design for a new process to make the ammonia-producing Haber-Bosch process more sustainable by reducing its CO2 emissions. It presents different elements of a process design with most importantly; process diagrams, mass and energy balances and a techno-economic analysis. The most important differences in this process is the use of water electrolysis and nitrogen production. This process emits approximately 50% less CO2 than regular Haber-Bosch methods. Nevertheless, the techno-economic analysis shows that this method is very expensive and that ammonia can only be sold at an acceptable price conform to the market with subsidies on electricity prices and can only become competitive if CO2 taxes are implemented for classic Haber-Bosch plants.

The intensification of human and industrial activities since the Industrial Revolution has led to a significant increase in global greenhouse gas emissions, posing a threat to life on our planet. As the transportation sector contributes to 23% of global CO2 emissions, it is imperative to reduce its carbon footprint. Developing a worldwide sustainable biofuel production chain is crucial for this purpose. The Biomass4transport project, a collaboration between TU Delft and the Biomass Technology Group, aims to achieve this by focusing on the production of second-generation biofuels in the Dutch context. In this context, a techno-economic analysis of a Power and Biomass to Liquid (PBtL) plant that incorporates water electrolysis, pyrolysis oil gasification, and synthesis gas upgrading for gasoline production is presented. The PBtL plant processes 5000 kg/h of pine wood-derived pyrolysis oil, which undergoes gasification in an oxygen-blown entrained flow gasifier. Subsequent purification steps include cyclones, filters, for the removal of particulate matter and solid ZnO sorbents for the removal of H2S. A solid oxide electrolysis cell produces hydrogen and oxygen streams; the former adjusts the H2:COx ratio before syngas upgrading, while the latter serves as an oxidizing agent in the gasifier. The synthesis gas is converted to dimethyl ether (DME) in a one-step direct conversion membrane reactor, enabling in-situ water removal and enhanced conversion performance. In a subsequent reactor, DME is upgraded to a hydrocarbon mixture, which is further processed to obtain gasoline and LPG. The process has been modelled by integrating Aspen Plus, Matlab - where an isothermal plug flow membrane reactor model has been coded - and Excel. Material recycling and heat integration strategies have been employed to enhance the plant’s performance in terms of product yield and energy efficiency. Finally, an economic analysis entailing the calculation of the Net Present Value (NPV) of the plant has been conducted, to assess the conditions under which the plant becomes profitable. The process has an energy efficiency of 51.8% but could potentially rise to 61.8% with an optimized strategy for hydrogen extraction from the sweep gas of the DME membrane reactor. Due to the absence of CO2 extraction along the process, the carbon efficiency of the process is 95.7%. Both values are higher than the ones of PBtL processes based on hydrogen-enhanced methanol-to-gasoline processes found in literature. Additionally, the economic analysis showed that the plant is not profitable in the current market conditions. However, with a decline in the price of electricity and/or a reduction in the taxation rate for gasoline, the plant could become profitable, as shown by the sensitivity analysis on the NPV.

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.