In connection to the increase of emissions of greenhouse gases, electrification of the society is pointed out as absolute necessary to achieve the climate goals. To succeed with this, a substantial proportion of the intermittent electricity production needs, with the help from technical solutions, be used as a buffer for this production. The production of renewable hydrogen gas is seen as one of the solutions. The purpose of this study is to function as a foundation for a pilot study for establishment of production of renewable hydrogen which Jämtkraft will conduct during 2023. The study is compiled with information from updated science reports and studies, authorities or equate sources, Jämtkraft and workshops. The production cost of hydrogen gas has been set to price of electricity, three sizes of electrolysers and two types of electrolysers. The selling price has been divided into the transport sector and the industry sector. The calculations have been made with help from calculation methods from Jämtkraft and according to levelized cost of hydrogen formula. It is clear the production cost of hydrogen strongly correlates with the electricity price. The size of the electrolyser also affects, a larger electrolyser decreases the production costs of hydrogen. The difference between types of electrolysers do not affect the cost significantly, rather the placement and energy source to the hydrogen production. In comparison to 2020, the competitiveness for hydrogen within the transport sector has increased. The increase of the electricity cost has decreased the competitiveness within the industry sector. For economic success of an establishment of hydrogen production in Jämtland a careful analyse of customer interest must be made and an adjustment of selling price according to the electricity price. An investment rather towards the transport sector rather than the industry sector is to recommend. / I samband med de ökade utsläppen av växthusgaser, anses elektrifiering av samhället vara absolut nödvändigt för att uppnå klimatmålen. För att lyckas med detta, krävs det att en storandel av den intermittenta elproduktionen genom tekniska lösningar kan nyttjas som en buffert för denna produktion. Där ses produktion av förnyelsebar vätgas som en avlösningarna. Syftet med studien är att fungera som underlag för den förstudie för etableringav produktion av förnyelsebar vätgas som Jämtkraft genomför under 2023. Studien har sammanställts med information från uppdaterade forskningsstudier, myndigheter ellerl ikställda källor, Jämtkraft samt workshops. Vätgasproduktionskostanden har ställts mot elpris, tre storlekar på elektrolysör samt två typer av elektrolysör. Försäljningspriset har fördelats på transport-, och industrisektor. Beräkningarna har gjort med kalkylmetoder från Jämtkraft samt enligt Levelized Cost of Hydrogen- modellen. Det är tydligt är att vätgasproduktionskostanden korrelerar stark med elpriset. Även storleken på elektrolysör påverkar, en större elektrolysör minskar vätgasproduktionskostnaden. Typ av elektrolysör påverkar inte kostnaden nämnvärt, utan mer placering och vilken energityp som är källa till vätgasen. Sett mot 2020 har konkurrenskraften för vätgas inom transportsektorn ökat. Ökningen av elkostnaden, sett mot 2020, har bidragit till en minskad konkurrenskraft mot industrisektorn. För att ekonomiskt lyckas med en etablering av förnyelsebar vätgasproduktion i Jämtlands län måste en noggrann kundintressenanalys göras samt anpassa försäljningspriset efter elpriset. En satsning mot transportsektorn snarare än industrisektorn är att rekommendera. / <p>2023-08-22</p>

The European Energy system is currently transitioning towards a reduced use of fossil fuels and increasing use of renewable energy. Hydrogen as energy carrier for renewable electricity has a potential to play a significant role in this transition. It can be stored and transported in its gaseous or liquid state, and utilized in industries that require highprocess heat, which makes them difficult to decarbonize. Further, hydrogen storage canbe employed to store over‐produced renewable electricity in large scale and for long periods of time. This research aims to develop a methodology to conduct a layout and dispatch optimization for utilizing locally produced hydrogen. The objective is to find the least cost supply pathway for a defined demand. In this case study, hydrogen is produced by water electrolysis supplied by the local electricity grid and renewable electricity, such as solar PV, onshore and offshore wind turbines. The scope is limited to gaseous hydrogen thereby the distribution is also limited to pipelines or road trucks. The optimized supplychain comprises four main stages: I) electricity generation and storage; II) hydrogen production; III) hydrogen compression and storage; IV) hydrogen transportation to the end consumer. It results in the system's optimum hourly dispatch schedule and a proposed least‐cost layout. The developed methodology is finally applied to an industrial case study in Sweden, for which scenarios with varying boundary conditions are tested. The least cost supply chain for the case study resulted in a system solely supplied with electricity purchased from the grid, a PEM electrolyzer, a hydrogen storage in a Lined Rock Cavern, and hydrogen transport via pipeline. The lowest Levelized Cost of Hydrogen from electricity purchase until delivery is 5.17 EUR/kgH2. The study concludes that there is no one optimum solution for all and the constraints of the optimization problem need to be evaluated case by case.The study further highlights that intermittency and peaks of both electricity availability and hydrogen demand can lead to an increase in system cost owing to the oversizing and storage needs. / Det europeiska energisystemet är för närvarande i en övergångsprocess mot en minskande användning av fossila bränslen och en ökande användning av förnybar energi. Vätgas som energibärare för förnybar el har potential att spela en viktig roll i denna övergång. Vätgas kan lagras och transporteras i gasform eller flytande form, och användas i industrier som kräver hög processvärme vars koldioxidutsläpp därför är svåra att minska. Vidare kan vätgaslagring användas för att lagra överproducerad förnybar el istor skala och under långa perioder. Denna forskning syftar till att utveckla en metod för layout och distributions optimering för utnyttjandet av lokalt producerad vätgas. Målet är att hitta den minst kostsamma försörjningsvägen för en definierad efterfrågan. I den här fallstudien produceras vätgas genom vattenelektrolys som försörjs av det lokala elnätet och förnybar el, t.ex. solceller, vindkraftverk på land och till havs. Omfattningen är begränsad till gasformig vätgas och därmed är distributionen också begränsad till rörledningar eller lastbilar. Den optimerade försörjningskedjan består av fyra huvudsteg: I) elproduktion och lagring, II) vätgasproduktion, III) komprimering och lagring av vätgas, IV) transport av vätgas till slutkonsumenten. Metodens output är systemets optimala timplan och ett förslag till layout med den lägsta kostnaden.  Den utvecklade metoden tillämpas slutligen i en industriell fallstudie i Sverige, för vilken scenarier med varierande randvillkor testas. Den minst kostsamma försörjningskedjan för fallstudien resulterade i ett system som enbart försörjs med el som köps från nätet, en PEM‐elektrolyser, ett magasin för vätgaslagring i ett fodrat bergrum och vätgastransport via en rörledning. Den lägsta Levelized Cost för vätgas från el inköp till leverans är 5,17EUR/ kgH2. I studien dras slutsatsen att det inte finns någon optimal lösning i allmänhet och att begränsningarna i optimeringsproblemet måste utvärderas från fall till fall. Studien belyser vidare att ostadighet och toppar i både eltillgången och efterfrågan på vätgas kan leda till en ökning av systemkostnaderna på grund av överdimensionering och lagringsbehov.

Norway has already an almost emission-free power production and its sales of zero-emission light-duty vehicles surpassed 30% in 2018; a natural next challenge is to identify ways to reduce emissions of heavyduty vehicles. In this work the possibilities to deploy Fuel Cell Electric Trucks (FCET) on the route Oslo-Trondheim are analyzed by doing a techno-economic analysis. The literature study identified that in average 932 kton goods where transported between the cities. The preferred road choice goes through Østerdalen and that an average load for a long-distance truck is 16 tons. The methodology used in the study is based on cost curves for both truck and infrastructure, and a case study with various scenarios is evaluated to find a profitable business case for both an FCET fleet and its infrastructure. The cost curves for trucks are based on total cost of ownership (TCO) as a function of hydrogen price, while the levelized cost of hydrogen (LCOH) is used to present the cost of infrastructure. An analysis was made to identify the trucks component sizes and a FCET for this route would require an onboard hydrogen storage of 46 kg, a fuel cell stack with a nominal power of 200 kW, a battery of 100 kWh (min SOC 22%), and an electric motor with a rated power of 402 kW. TCO was calculated both for an FCET based on the dimensioned components and a biodiesel truck. The results show that an FCET purchased in 2020 can be competitive with biodiesel with a hydrogen price of 38.6 NOK/kgH2. While the hydrogen price can increase to 71.8 NOK/ kgH2 if the FCET is purchased in 2030. To identify the most suitable infrastructure, four different designs of hydrogen refueling stations (HRS) were compared. Furthermore, hydrogen production units (HPUs) with both alkaline or PEM type water electrolyzer were compared. The analysis in this study showed that the most cost competitive option was a 350-bar HRS without cooling, which only can serve type III onboard storage tanks. A HPU with alkaline electrolyzer was the most price competitive alternative. In case each HRS is refueling more than 7 FCETs per day, an HPU in direct connection to HRS is the preferred infrastructure setup. Three HRS are required along the route to ensure a minimum service level for the FCETs. When the TCO of the fuel cell truck and LCOH of the hydrogen infrastructure were compared for a 2020 scenario, no feasible solution was identified. The cost of installing three HRS in 2020, serving a fleet of 14-24 trucks, would cost 16.0 – 17.6 million NOK/year more than a fleet based on biodiesel trucks. In a future scenario, where both the FCET and infrastructure costs decrease due to expected learning curves, a business case can be found if at least 5 FCETs were refueling at each HRS on daily basis, which corresponds to a total fleet of approx. 24 FCETs. Finally, a set of clear recommendations on how to improve the techno-economic analysis in future studies are provided. Both by identifying areas lacking sufficient documentation and by providing steps how the tecno-economic model could be enhanced. / Norge har redan en nästintill utsläppsfri elproduktion och nollutsläppsbilar stod för mer än 30% av nybilsförsäljningen under år 2018. En naturlig nästa utmaning är att finna sätt att minska utsläpp från lastbilar. I detta examensarbete analyseras möjligheterna att introducera bränslecellslastbilar (FCET) efter dess engelska förkortning) på sträckan Oslo - Trondheim genom att göra en teknisk-ekonomisk bedömning. Litteraturstudien visade att i genomsnitt 932 kton gods fraktas mellan städerna, att vägen genom Østerdalen är att föredra och att genomsnittlig last för en långtradare är 16 ton. Arbetets metod bygger på att identifiera kostnadskurvor för både lastbilar och infrastruktur. Dessa kurvor kombineras i olika scenarier för att finna omständigheter där både en FCET-flotta och dess infrastruktur är lönsamma. Kostnadskurvorna för lastbilar baseras på den totala ägandekostnaden (TCO) efter dess engelska förkortning) som en funktion av vätgaspriset, medan den utjämnade kostnaden för vätgas (LCOH) efter dess engelska förkortning) används för att presentera kostnaden för infrastruktur. En analys gjordes för att finna passande storlek på FCET drivlina. För den specifika sträckan krävs en hydrogentank på 46 kg, en bränslecellstack med nominell effekt på 200 kW, ett batteri på 100 kWh (min SOC 22%) och en elmotor med nominell effekt på 402 kW. TCO beräknades både för en FCET baserat på de dimensionerade komponenterna och en lastbil som går på biodiesel. En FCET som köps 2020 blir konkurrenskraftig om vätgaspriset är 38,6 NOK/kgH2, medan vätgaspriset kan öka till 71,8 NOK/kgH2 om FCET köps 2030. Skillnaden är baserad på en framtida prisnedgång för FCET. För att finna den mest lämpliga lösningen på infrastruktur; analyserades fyra olika utformningar av vätgaspåfyllningsstationer (HRS). I tillägg jämfördes vätgasproduktionsenheter (HPU) baserat på antingen alkalisk eller PEM-typ av elektrolysator. Resultaten visade at en 350 bar HRS utan kylning, som endast kan fylla typ III lagringstankar, som det billigaste alternativet. Den alkaliska elektrolysatorn kunde producera vätgas för något lägre kostnad. Det billigaste alternativet för infrastruktur av de olika framtagna scenarios var att placera HPU bredvid HRS om minst 7 FCET tankar dagligen på varje station. Minst 3 HRS krävs längs rutten för att tillhandahålla en minsta servicenivå för FCET. När TCO för bränslecellslastbil och LCOH för infrastruktur jämfördes för ett 2020-scenario så fanns det ingen lönsam lösning. Kostnaden för att installera 3 HRS år 2020 som betjänar en lastbilflotta mellan 14-24 lastbilar skulle kosta 16,0 - 17,6 miljoner NOK/år mer än en lastbilsflotta som går på biodiesel. I ett framtida scenario där både FCET- och infrastrukturkostnaderna minskar på grund av större produktionsvolymer så kan vätgassatsning bli lönsam om minst 5 FCET tankar dagligen på varje HRS. Det motsvarar en lastbilsflotta på omkring 24 lastbilar för hela rutten. Till slut finns en rad klara rekommendationer om hur den tekno-ekonomiska analysen kan förbättras. Det upptäcktes både områden med otillräcklig dokumentation och summerades hur den teknoekonomiska modellen kan förbättras.

This project proposes a hybrid system for hydrogen production, which includes a connection to the grid, a source of renewable energies, namely photovoltaic (PV), a Battery Energy Storage System (BESS), and a PEM (Proton Exchange Membrane) electrolyzer modelled from commercial technologies available. A dispatch optimization algorithm will evaluate the price of the energy inputs and the power available from the solar PV system and will decide the operation on an hourly basis to maximize net profit in a year timeframe. This algorithm will have a daily hydrogen production constraint. When the price of electricity is low, the energy is used for two purposes. First, to electrolyze water in the electrolyzer system and second, to store it in the BESS. The stored energy will be used to produce hydrogen when electricity prices are high or inject back to the grid when it is economically sound to do. The PV input will be used to alleviate the need for energy from the grid, therefore, it can be used to feed the electrolyzer or to store in the batteries or to inject back to the grid. In this study, a multi-energy system is modelled and its operation strategy for green hydrogen production is analyzed. Four topological scenarios were chosen, which include Scenario 1 (Grid + PEM), Scenario 2 (Scenario 1 + BESS), Scenario 3 (Scenario 2 + Grid injection), and Scenario 4 (Scenario 3 + Solar PV). These scenarios facilitate a comprehensive assessment of the system's economic and environmental performance contingent on the installed assets. In addition to the scenario analysis, the study broadens its scope by exploring two diverse geographical regions, Sweden and Spain, as case studies. This comparative approach offers invaluable insights into the role of factors like lower electricity prices and reduced solar energy availability, as observed in the Swedish case, versus the dynamics of higher electricity prices and abundant solar energy in the Spanish context. Lastly, the research undertakes a thorough sensitivity analysis, considering two pivotal factors with great influence over the system's behavior: hydrogen pricing and BESS capacity. This exploration enriches our understanding of how variations in these factors can impact the system's operational and economic viability. / Detta arbete presenterar ett hybridsystem för produktion av vätgas som integrerar elnätsanslutning, förnybar energiförsörjning genom solceller (PV), ett batterilager (BESS) och en PEM-elektrolysör. För detta energisystem har en optimeringsalgoritm för systemdrift skapats. Denna algoritm utvärderar energipriser och tillgänglig kapacitet från PV-systemet, och driftar systemet på timbasis för att optimera nettovinsten över ett år, med dagliga produktionsgränser för vätgas. När elpriset är lågt används energin för två ändamål: Att elektrolysera vatten i elektrolyssystemet, och att lagra det i batterilagret (BESS). Den lagrade energin från BESS kommer att användas för att producera vätgas när elpriserna är höga eller för att injicera tillbaka i elnätet när det är ekonomiskt försvarbart. Energin från PV-systemet används för att lindra behovet av energi från elnätet och kan användas för att driva elektrolysören, eller för att lagra i batterierna, eller för att injicera tillbaka i elnätet. I denna studie modelleras en elektrolysör, baserat på kommersiellt tillgängliga teknologier, och en driftsstrategi utvecklas för produktionen av grön vätgas. Fyra unika scenarier valdes ut: Scenario 1 (Nät + PEM), Scenario 2 (Scenario 1 + BESS), Scenario 3 (Scenario 2 + Injektion till Elnät) och Scenario 4 (Scenario 3 + Solenergi från PV). Dessa scenarier underlättar en omfattande bedömning av systemets ekonomiska och miljömässiga prestanda beroende på installeradetillgångar. Utöver scenarioanalysen vidgar studien sin omfattning genom att utforska två olika geografiska regioner, Sverige och Spanien, som fallstudier. Denna jämförelse ger värdefulla insikter i systemfaktorernas roll, där det Svenska fallet (med lägre elpriser och minskad tillgänglighet av solenergi) ställs emot the Spanska fallet (med högre elpriser och rikligt med solenergi). Slutligen genomför forskningen en noggrann känslighetsanalys och beaktar två avgörande faktorer med stor påverkan över systemets beteende: Priset på såld vätgas och BESS-kapaciteten. Denna utforskning berikar vår förståelse för hur variationer i dessa faktorer kan påverka systemets operativa och ekonomiska livskraft.

This project proposes a solar-driven hybrid system for electricity generation and hydrogen production, which includes concentrated solar power (CSP), photovoltaic (PV), solid oxide electrolyser (SOEC). Electricity from the CSP and PV provides a continuous 24/7 supply to meet demand-side power consumption. When demand-side power consumption is low, the excess power is used to electrolyse water in the SOEC system. In this study, an SOEC is modelled, operation strategy for the solar-driven hybrid system is developed, the techno-economic performance of the overall system is evaluated, and sensitivity analysis is performed. For the modelling part, first develop an SOEC component in Matlab and Trnsys by considering the electrochemical model, thermal model and electric model. Second, design the hybrid system layout and simulate the system under 8760 hours in Matlab and Trnsys. The hybrid system is divided into five blocks: Heat Energy Source Block, Thermal Energy Storage Block, Rankine Cycle Block, Photovoltaic Block, Power to Hydrogen (PtH) Block. The operation strategy is: the heat is collected using a tower solar receiver and stored in tanks by heat transfer fluid molten salt. These thermal energy heats the water in heat exchangers and the resulting high temperature water vapour is used in steam turbine to generate electricity; at the same time part of the heat transfer fluid heats the feedwater in the PtH block and the resulting high temperature water vapour is used in SOEC for hydrogen production, if the operation temperature of steam in SOEC is not reached after heat exchange, the electric heater will heat the steam to raise the temperature. The CSP and PV provide electricity to demand side and SOEC. The produced hydrogen will be transported by truck or ship after compressed. For results part, the minimum CSP configurations to provide a 24/7 demand-side electricity consumption is a solar multiple (SM) with 2 and thermal storage (TES) size of 14 hours. SOEC stack has the best techno-economic performance at a nominal power of 275 Watt. The hybrid system has a levelised cost of electricity (LCOE) at 0.219 USD/kWh and a levelised cost of hydrogen (LCOH) at 7.5 USD/Kg. There are several sensitivity parameters for increase the energy productivity and decrease levelised cost. The larger the SM, the better the ability to generate power. The larger the TES size, the more the hourly generation is similar, otherwise it will fluctuate more. Increasing the SM results in a higher LCOE and a significantly lower LCOH. Increasing TES size also increases the LCOE, whereas the TES size has a marginal impact on the decrease of LCOH. Increased installed capacity inevitably leads to increased power generation. The increasing total power capacity makes the surplus power at the same demand side increase, so the SOEC runs at higher input power and the total hydrogen production increases, resulting in a lower LCOH. The effect of SOEC capacity on LCOH depends on the relationship between input power and SOEC nominal power. Higher operation temperature of SOEC leads to the lower the reversible voltage and an increasing consumption for water vapour. However, when the water vapour concentration is too high, the electrolysis current will instead drop, meaning that the rate of hydrogen production will drop.

Hydrogen can be produced via water electrolysis, a process powered by electricity, and is often called green hydrogen if the electricity source is renewable. The purpose of this thesis is to investigate the levelised cost of hydrogen, LCOH, from two hypothetical scenarios of green hydrogen production at onshore wind farm sites. The hydrogen is used in steel manufacturing. One scenario is set in Chile, a country with excellent wind conditions, where a large wind farm of around 1 GW supplies both a hydrogen and ammonia production. Ammonia is used as a hydrogen carrier since it is easier to transport, and the ammonia is shipped to Sweden where it is decomposed into hydrogen. The Swedish scenario includes three cases with wind farms of 28.5, 114 and 285 MW (case 1, 2 and 3), where the sites are located close to the steel plant. Both the Chilean and Swedish scenarios consist of a base case and a sensitivity analysis, all simulated in MATLAB. Parameters such as equipment efficiency and cost, levelised cost of wind energy, shipping and transportation costs, electricity price and electrolyser size were analysed to see how they affect the LCOH.  The results showed that the Chilean case both could meet the hydrogen demand of a commercial steel plant and has a lower LCOH than most Swedish scenarios. The LCOH in the base case was 2.17 €/kg H2 for the Chilean case and 6.71, 6.29 and 5.14 €/kg H2, respectively, for case 1, 2 and 3. The sensitivity analysis showed that case 3 had a similar or lower LCOH than the Chilean case when it was connected to the grid, and could sell excess wind electricity, or for electrolysers of at least 100 MW. Case 3 could supply the smallest of the suggested steel plant sizes, and it would require an around three times larger wind farm and hydrogen production site to reach the level of the Chilean case. However, the Swedish case could be preferred if other factors, such as security of supply, local connection or the exclusion of fossil fueled transports, are more important than low cost and hydrogen volume.

Hydrogen, as a dense energy carrier with low carbon footprint, will play an important role in energy transition. It only produces water after reaction which is totally environment friendly. There are many different technologies for hydrogen production. Steam Methane Reforming (SMR) is the most largely commercialized technology in the market, but it has a large carbon footprint in its conventional way. An Electrified Steam Methane Reforming (ESMR) has been proposed to improve the reforming efficiency and reduce the carbon footprint. By using biomethane as feedstock, the carbon footprint could be completely removed from the production itself. Water Electrolysis (WE) is now at the beginning stage of large-scale commercializing, but it’s limited due to the high energy consumption which makes this solution rather expensive. In order to decide which technology is better to cater to local climate policies and energy resources’ availabilities, a techno-economic study is essential for the market investigation. This work briefly introduced a technological comparison between the ESMR and WE technologies, followed by a techno-economic analysis in both grid-connected solutions and decentralized solutions. Biomethane is chosen as feedstock of ESMR technologies to produce greener hydrogen. In grid connected cases, the lowest and highest electricity price in SE1 to SE4 are considered to decide the Levelized Cost of Hydrogen (LCOH) range in these 4 areas for WE technologies, and together with the lowest and highest biomethane, LCOH for ESMR technologies are decided. In decentralized cases, wind farm and PV farm are considered to evaluate the LCOH of each technology. Generally speaking, in grid connected cases, SE1 and SE2 in Sweden are better locations to build up the hydrogen production plants due to the cheap electricity price there. ESMR is the least sensitive solution to electricity price fluctuation at an average rate 19.5%, while it’s 64.15% with PEM and 65.45% with AWE. Meanwhile ESMR is also the cheapest among all the technologies.In decentralized cases, wind farm solution is slightly cheaper than PV farm solution for all the technologies. Wind farm is feasible in whole Sweden while PV farm is only available in SE3 and SE4 in south of Sweden due to the geography and climate limitations which restricted the solar radiation conditions.When it comes to a specific solution, there are boundaries across different technologies, e.g., in ESMR, when the grid electricity price is lower than 715 SEK/MWh, grid connected ESMR is cheaper than wind farm ESMR, vice versa.

The global hydrogen demand is steadily increasing, and one way of accelerating the green hydrogen supply is to stimulate the green hydrogen economy. Utilization of waste heat from hydrogen production can increase the profitability of produced green hydrogen. Therefore, the aim of this study is to propose a system for integration of waste heat on the district heating (DH) network in Luleå, Sweden. Furthermore, an economic evaluation of the proposed system was conducted. In this study, the system was developed and investigated for two cases i.e. for a PEM and alkaline electrolyzer with an installed capacity of 100 MW. A large-scale heat pump and a heat exchanger were further added to the system to integrate the waste heat on the DH-network, while simultaneously providing cooling to the electrolyzer stack. The system was modelled for static conditions in the software MATLAB, with retrieved hourly DH data from Luleå Energi. The results showed that 203 060 MWhth can be extracted from the PEM electrolyzer with a waste heat temperature of 79 oC, while 171 770 MWhth can be integrated on the DH network annually. For the alkaline electrolyzer, 310 630 MWhth can be extracted at a waste heat temperature of 80 oC, while 226 220 MWhth can be integrated on the DH annually. The overall system efficiency is 94.7 % and 88.4 % for PEM and alkaline connected systems, respectively. Furthermore, the Levelized Cost of Heat (LCOH) is 0.218 SEK/kWhth and 0.23 SEK/kWhth for a PEM and alkaline connected system, respectively. For future scenarios with fourth generation of DH-networks, it is predicted that the LCOH can reach 0.018 SEK/kWth for a PEM electrolyzer system, and 0.017 SEK/kWth for an alkaline electrolyzer system. One conclusion that can be drawn from this study is that the utilized heat from the proposed system is price competitive in comparison with other thermal energy sources.

In conjunction with Sweden's goal of reducing emissions and dependence on fossil fuels in the transport sector, hydrogen technology has received considerable attention. Today, several studies are being carried out into hydrogen technology that focus on developing the production, application, storage and distribution of hydrogen. Energimyndigheten is investigating various strategies for hydrogen development to increase hydrogen production, develop green transports and opportunities for energy storage in Sweden. This study is about estimating the potential for hydrogen in heavy-duty vehicles in Västerås and investigating various possibilities for local hydrogen production. Gasification plants with capacities of 1, 5 and 10 MW are studied to analyze the gasification plant's design, operating conditions, costs and investment profitability. In addition, it is investigating the possibility of building a hydrogen filling station with hydrogen produced by an electrolysis plant in Rocklunda. For the electrolysis plant in Rocklunda, alkaline electrolysis from Nel Hydrogen (A150 and A300) with a power of 660 and 1320 kW and a daily production of 320 and 640 kg of hydrogen respectively are investigated. The electrolysis is connected to the electricity grid and the PV system in Rocklunda, while waste heat from the electrolysis is used to balance the district heating network.   The results of this study show that the potential for hydrogen can vary depending on the number of heavy hydrogen-powered vehicles, the mileage and the depreciation period. Different scenarios are discussed to get an estimation of what the development of hydrogen demand may look like. For a long-term scenario with high hydrogen demand, hydrogen production with a gasification plant is considered suitable. The total investment costs are estimated at 2.3, 4.7 and 7.7 million euros for 1, 5 and 10 MW plants. The production cost for each plant is estimated at 3.45, 2.28 and 2.12 euros per kg of hydrogen. The results also show that efficiency and costs for operation and maintenance are factors that have the greatest impact on production costs. For the net present value, efficiency and sales price are two factors that constitute the greatest impact.  For the A150 and a hydrogen filling station with a storage capacity of 400 kg per day, the total investment cost is estimated at 2.5 million euros. For the A300 and a hydrogen filling station with a capacity of 800 kg per day, the total investment cost amounts to 4.7 million euros. MATLAB is used to optimize hydrogen production that meets the estimated hydrogen demand and minimize costs in Rocklunda. The production cost per kg of hydrogen is estimated at 8 and 7 euros for the A150 and A300. For the electrolysis plant, the results show that the price of electricity has the greatest impact on the production cost, while the net present value is most affected by the electricity price and sales price for hydrogen. Furthermore, the results show that approximately 70% of the annual hydrogen production takes place with the electricity grid between 21 and 05 when the electricity price is low, which means that the hydrogen is not classified as green hydrogen.   The conclusion that has been drawn in this study is that hydrogen enables the electrification of heavy-duty vehicles with long driving distances. In 2024, it is expected that there will be the possibility of selling produced green hydrogen to build hydrogen filling stations in Sweden. Hydrogen production with an electrolysis plant in Rocklunda is a suitable method that can meet the hydrogen demand in the short term. However, this means higher costs for one kg of produced hydrogen.   To produce green hydrogen, green electricity from local electricity grid must be used in the electrolysis. Increased capacity on the PV system in Rocklunda is an alternative for increasing the proportion of green hydrogen. Hydrogen production with a gasification plant entails high investment costs but is suitable for large-scale production, which means that a high demand in the market is required to ensure investment profitability.

In face of climate change, Europe and other global actors are in the process of transitioning to carbon-neutral economies, aiming to phase out of fossil fuels and power industries with renewable energies. Hydrogen is going to play a crucial role in the transition, replacing fossil fuels in hard-to-decarbonize industries and acting as energy carrier and energy storage for renewable electricity. However, the hydrogen production method with the lowest carbon intensity, water electrolysis in combination with renewable electricity, is often not cost competitive to other production methods. Even though policies and initiatives are providing subsidies to scale up low-carbon hydrogen production, companies hesitate to invest due to the complexity of hydrogen production systems and the uncertainties of cost competitiveness. This research aims to develop a tool for optimizing the capacity of a water electrolysis system to produce low-carbon hydrogen and to lay the groundwork for optimizing the operation of electrolysis hydrogen production plants. The objective is to find the optimal plant capacity to achieve the lowest cost of hydrogen production for a defined hydrogen demand and energy supply. The scope is limited to the electrolysis system as optimizing asset which is modeled with technology-specific costs and characteristics, gained from manufacturer interviews and internal company data. This includes the often neglected characteristics of load-dependent efficiency and degradation effects. Further, the tool is enabled to buy and sell electricity on the spot market according to predicted prices in order to minimize the electricity costs. The developed tool is tested, benchmarked and applied to two different industry-based test scenarios in Germany and Portugal. The test scenario in Germany describes a mid-scale hydrogen production case for a transport application with a demand increase over 10 years (80 to 1,800 tons per year) and regional renewable energy supply via power purchase agreements. The lowest costs of hydrogen production for this scenario can be reached with an alkaline electrolysis system of a capacity of 16 MWel considering only renewable energy sources, achieving a LCOH of 4.75 €/kg of green hydrogen. The second test scenario describes a large-scale production case in Portugal for application in the refinery industry. The yearly hydrogen demand increases from 5,000 tons up to 17,100 tons within three years and is assumed to stay constant for the residual years. The electricity for the electrolysis process is secured through large solar PV and offshore wind power purchase agreements. Utilizing the alkaline electrolysis technology with a capacity of 128 MWel, a LCOH of 3.31 €/kg of green hydrogen can be achieved at the output point of the plant. The study concludes that the optimal solution and the achievable hydrogen production costs are highly dependent on the hydrogen demand (quantity and profile), the energy supply (quantity, profile, costs), and the chosen technology (efficiency, degradation, costs) and need to be evaluated under the case-specific prerequisites. The thesis further highlights the significant impact of the electrolysis system efficiency and capital expenditures on the capacity decision and achievable hydrogen production costs. / Mot bakgrund av klimatförändringarna håller Europa och andra globala aktörer på att ställa om till koldioxidneutrala ekonomier, med målet att fasa ut fossila bränslen och driva industrier med förnybara energikällor. Vätgas kommer att spela en avgörande roll i omställningen genom att ersätta fossila bränslen i industrier som är svåra att koldioxidneutralisera och fungera som energibärare och energilagring för förnybar el. Den metod för vätgasproduktion som har lägst koldioxidintensitet, vattenelektrolys i kombination med förnybar el, är dock ofta inte kostnadsmässigt konkurrenskraftig i förhållande till andra produktionsmetoder. Även om politik och initiativ tillhandahåller subventioner för att skala upp koldioxidsnål vätgasproduktion, tvekar företagen på grund av komplexiteten i vätgasproduktionssystemen och osäkerheten kring konkurrenskraften. Denna forskning syftar till att utveckla ett verktyg för att optimera kapaciteten hos ett vattenelektrolyssystem för att producera grön vätgas och att lägga grunden för att optimera driften av elektrolysanläggningar för vätgasproduktion. Målet är att hitta den optimala anläggningskapaciteten för att uppnå den lägsta kostnaden för vätgasproduktion för en definierad vätgasefterfrågan och definierad energiförsörjning. Omfattningen är begränsad till elektrolyssystemet som en optimerande tillgång som modelleras med teknikspecifika kostnader och egenskaper, hämtade från tillverkar-intervjuer och från företags interna marknadsdata. Detta inkluderar de ofta försummade egenskaperna hos lastberoende effektivitet och degraderingseffekter. Vidare kan verktyget köpa och sälja el på spotmarknaden enligt förutspådda priser för att minimera elkostnaderna. Det utvecklade verktyget testas, jämförs och tillämpas på två olika industribaserade testscenarier i Tyskland och Portugal. Testscenariot i Tyskland beskriver en medelstor vätgasproduktion för en transporttillämpning där efterfrågan ökar över 10 år (80 till 1 800 ton per år) och regional förnybar energiförsörjning via energiköpsavtal (power purchase agreements). De lägsta kostnaderna för vätgasproduktion för detta scenario kan uppnås med ett alkaliskt elektrolyssystem med en kapacitet på 16 MWel som endast använder förnyelsebara energikällor och uppnår en LCOH på 4,75 €/kg grön vätgas. Det andra testscenariot beskriver en storskalig vätgasproduktion i Portugal för tillämpning inom raffinaderi-industrin. Det årliga vätgasbehovet ökas från 5 000 ton till 17 100 ton inom tre år och antogs förbli konstant under de återstående åren. El för elektrolysprocessen säkras genom stora energiköpsavtal (power purchase agreements) för solceller och havsbaserad vindkraft. Genom att använda alkalisk elektrolysteknik med en kapacitet på 128 MWel kan en LCOH på 3,31 €/kg grön vätgas uppnås vid anläggningens utgångspunkt. Studien visar att den optimala lösningen och de uppnåbara vätgasproduktionskostnaderna är starkt beroende av vätgasbehovet (mängd och profil), energiförsörjningen (mängd, profil, kostnader) och den valda tekniken (effektivitet, nedbrytning, kostnader) och måste utvärderas utifrån de fallspecifika förutsättningarna. Avhandlingen belyser vidare den betydande inverkan som elektrolyssystemets effektivitet och kapitalutgifter har på kapacitetsbeslutet och de uppnåeliga kostnaderna för vätgasproduktion.