Norway

This report is part of DNV’s suite of Energy Transition Outlook publications for 2021. It focuses on how key energy transition technologies will develop compete and interact in the coming five years.

Debate and uncertainty about the energy transition tend to focus on what technology can and can’t do. All too often such discussions involve wishful thinking advocacy of a favoured technology or reference to outdated information. Through this report we bring insights derived from our daily work with the world’s leading energy players including producers transporters and end users. Each of the ten chapters that follow are written by our experts in the field – or in the case of maritime technologies on the ocean.

Because the pace of the transition is intensifying describing any given technology is like painting a fast-moving train. We have attempted to strike a balance between technical details and issues of safety efficiency cost and competitiveness. Transition technologies are deeply interlinked and in some cases interdependent; any discussion on green hydrogen for example must account for developments in renewable electricity hydrogen storage and transport systems and end-use technologies such as fuels cells.

Our selection of ten technologies is not exhaustive but each of these technologies is of particular interest for the pace and direction of the energy transition. They range from relatively mature technologies like solar PV to technologies like nuclear fusion which are some distance from commercialization but which have current R&D and prototyping worth watching. Together they cover most but not all key sectors. We describe expected developments for the coming five years which to a large extent will determine how the energy transition unfolds through to mid-century. As such this Technology Progress report is an essential supplement to our main Energy Transition Outlook forecast.

Our aim is to make an objective and realistic assessment of the status of these technologies and evaluate how they contribute to the energy transition ahead. Attention to progress in these technologies will be critical for anyone concerned with energy.

A radical decarbonization pathway for the Norwegian society towards 2050 is presented. The paper focuses on the role of hydrogen in the transition when present Norwegian petroleum export is gradually phased out. The study is in line with EU initiatives to secure cooperation opportunities with neighbouring countries to establish an international hydrogen market. Three analytical perspectives are combined. The first uses energy models to investigate the role of hydrogen in an energy and power market perspective without considering hydrogen export. The second uses an economic equilibrium model to examine the potential role of hydrogen export in value creation. The third analysis is a socio-technical case study on the drivers and barriers for hydrogen production in Norway. Main conclusions are that access to renewable power and hydrogen are prerequisites for decarbonization of transport and industrial sectors in Norway and that hydrogen is a key to maintain a high level of economic activity. Structural changes in the economy impacts of new technologies and key enablers and barriers in this transition are discussed.

Population growth and the expansion of industries have increased energy demand and the use of fossil fuels as an energy source resulting in release of greenhouse gases (GHG) and increased air pollution. Countries are therefore looking for alternatives to fossil fuels for energy generation. Using hydrogen as an energy carrier is one of the most promising alternatives to replace fossil fuels in electricity generation. It is therefore essential to know how hydrogen is produced. Hydrogen can be produced by splitting the water molecules in an electrolyser using the abondand water resources which are covering around ⅔ of the Earth's surface. Electrolysers however require high-quality water with conductivity in the range of 0.1–1 μS/cm. In January 2018 there were 184 offshore oil and gas rigs in the North Sea which may be excellent sites for hydrogen production from seawater. The hydrogen production process reported in this paper is based on a proton exchange membrane (PEM) electrolyser with an input flow rate of 300 L/h. A financially optimal system for producing demineralized water from seawater with conductivity in the range of 0.1–1 μS/cm as the input for electrolyser by WAVE (Water Application Value Engine) design software was studied. The costs of producing hydrogen using the optimised system was calculated to be US$3.51/kg H2. The best option for low-cost power generation using renewable resources such as photovoltaic (PV) devices wind turbines as well as electricity from the grid was assessed considering the location of the case considered. All calculations were based on assumption of existing cable from the grid to the offshore meaning that the cost of cables and distribution infrastructure were not considered. Models were created using HOMER Pro (Hybrid Optimisation of Multiple Energy Resources) software to optimise the microgrids and the distributed energy resources under the assumption of a nominal discount rate inflation rate project lifetime and CO2 tax in Norway. Eight different scenarios were examined using HOMER Pro and the main findings being as follows:<br/>The cost of producing water with quality required by the electrolyser is low compared with the cost of electricity for operation of the electrolyser and therefore has little effect on the total cost of hydrogen production (less than 1%).<br/>The optimal solution was shown to be electricity from the grid which has the lowest levelised cost of energy (LCOE) of the options considered. The hydrogen production cost using electricity from the grid was about US$ 5/kg H2.<br/>Grid based electricity resulted in the lowest hydrogen production cost even when costs for CO2 emissions in Norway that will start to apply in 2025 was considered being approximately US$7.7/kg H2.<br/>From economical point of view wind energy was found to be a more economical than solar.

In the literature different energy carriers are proposed in future long-distance hydrogen value chains. Hydrogen can be stored and transported in different forms e.g. as compressed dense-phase hydrogen liquefied hydrogen and in chemically bound forms as different chemical hydrides. Recently different high-level value chain studies have made extrapolative investigations and compared such options with respect to energy efficiency and cost. Three recent journal papers overlap as the liquid hydrogen option has been considered in all three studies. The studies are not fully aligned in terms of underlying assumptions and battery limits. A comparison reveals partly vast differences in results for chain energy efficiency for long-distance liquid hydrogen transport which are attributable to distinct differences in the set of assumptions. Our comparison pinpoints the boiloff ratio i.e. evaporation losses due to heat ingress in liquid hydrogen storage tanks as the main cause of the differences and this assumption is further discussed. A review of spherical tank size and attributed boiloff ratios is presented for existing tanks of different vintage as well as for recently proposed designs. Furthermore the prospect for further extension of tanks size and reduction of boiloff ratio is discussed with a complementary discussion about the use of economic assumptions in extrapolative and predictive studies. Finally we discuss the impact of battery limits in hydrogen value chain studies and pinpoint knowledge needs and the need for a detailed bottom-up approach as a prerequisite for improving the understanding for pros and cons of the different hydrogen energy carriers.

Development of hydrogen facilities such as hydrogen refuelling stations (HRS) at scale is a fine balance between economy and safety where an optimal solution would both prevent showstoppers due to cost of increased safety measures and prevent showstoppers due to hydrogen accidents. A detailed Quantitative Risk Analysis (QRA) methodology is presented where the aim is to establish the total risk of the facility and use it to find the right level of safety features such as blast walls and layout. With upscaled hydrogen facilities comes larger area footprints and more potential leak points. These effects will cause increased possible consequence in terms of vapour cloud explosions and increased leak frequencies. Both effects contributing negative to the total risk of the hydrogen facility. At the same time as the number of such facilities is increasing rapidly the frequency of incidents can also increase. A risk-based approach is employed where inherently safe solutions is investigated and cost efficient and acceptable solutions can be established. The present QRA uses well established tools such as SAFETI FLACS and Express which are fitted for hydrogen risks. By using the established Explosion Risk Analysis tool Express the explosion risk inside the station can be found. By using CFD tools actively one can point at physical risk drivers such as equipment layout that can minimize gas cloud build-up on the station. The explosion simulations are further used to find the effects of e.g. blast wall on the pressures affecting on people on the other side of the wall. This is used together with the results from the SAFETI analysis to develop risk contours around the facility. Current standardized safety distances are discussed by considering the effects of scaling and risk drivers on the safety distances. The methodology can be used to develop certain requirement for how hydrogen facilities should be built inherently safe and in cost-efficient ways.

The overall ambition of the study has been to assess the commercial and operational viability of alternative marine fuels based on review existing academic and industry literature. The approach assesses how well six alternative fuels perform compared to LNG fuel on a set of 11 key parameters. Conventional fuels are not covered in this study however 2020 compliant fuels (HFO+scrubber and low sulphur fuels are included in the conclusion for comparative purposes.

Rising climate change ambitions require large-scale clean hydrogen production in the near term. “Blue” hydrogen from conventional steam methane reforming (SMR) with pre-combustion CO2 capture can fulfil this role. This study therefore presents techno-economic assessments of a range of SMR process configurations to minimize hydrogen production costs. Results showed that pre-combustion capture can avoid up to 80% of CO2 emissions cheaply at 35 €/ton but the final 20% of CO2 capture is much more expensive at a marginal CO2 avoidance cost around 150 €/ton. Thus post-combustion CO2 capture should be a better solution for avoiding the final 20% of CO2. Furthermore an advanced heat integration scheme that recovers most of the steam condensation enthalpy before the CO2 capture unit can reduce hydrogen production costs by about 6%. Two hybrid hydrogen production options were also assessed. First a “blue-green” hydrogen plant that uses clean electricity to heat the reformer achieved similar hydrogen production costs to the pure blue configuration. Second a “blue turquoise” configuration that replaces the pre-reformer with molten salt pyrolysis for converting higher hydrocarbons to a pure carbon product can significantly reduce costs if carbon has a similar value to hydrogen. In conclusion conventional pre-combustion CO2 capture from SMR is confirmed as a good solution for kickstarting the hydrogen economy and it can be tailored to various market conditions with respect to CO2 electricity and pure carbon prices.

The declining cost of renewable power has engendered growing interest in leveraging this power for the production of chemicals and synthetic fuels. Here renewable power is added to the gas-to-liquid (GTL) process through Fischer–Tropsch (FT) synthesis in order to increase process efficiency and reduce CO2 emissions. Accordingly two realistic configurations are considered which differ primarily in the syngas preparation step. In the first configuration solid oxide steam electrolysis cells (SOEC) in combination with an autothermal reformer (ATR) are used to produce synthesis gas with the right composition while in the second configuration an electrically-heated steam methane reformer (E-SMR) is utilized for syngas production. The results support the idea of adding power to the GTL process mainly by increased process efficiencies and reduced process emissions. Assuming renewable power is available the process emissions would be 200 and 400 gCO2 L1 syncrude for the first and second configurations respectively. Configuration 1 and 2 show 8 and 4 times less emission per liter syncrude produced respectively compared to a GTL plant without H2 addition with a process emission of 1570 gCO2 L1 syncrude. By studying the two designs based on FT production carbon efficiency and FT catalyst volume a better alternative is to add renewable power to the SOEC (configuration 1) rather than using it in an E-SMR (configuration 2). Given an electricity price of $100/MW h and natural gas price of 5 $ per GJ FT syncrude and H2 can be produced at a cost between $15/MW h and $16/MW h. These designs are considered to better utilize the available carbon resources and thus expedite the transition to a low-carbon economy

Liquefaction of hydrogen is a promising technology for transporting large quantities of hydrogen across long distances. A key challenge is the high power consumption. In this work we discuss refrigeration strategies that give minimum entropy production/exergy destruction in a plate-fin heat exchanger that cools the hydrogen from 47.8 K to 29.3 K. Two reference cases are studied; one where the feed stream enters at 20 bar and one where it enters at 80 bar. Catalyst in the hot layers speeds up the conversion of ortho-to para-hydrogen. Optimal control theory is used to formulate a minimization problem where the objective function is the total entropy production the control variable is the temperature of the refrigerant and the constrains are the balance equations for energy mass and momentum in the hot layers. The optimal refrigeration strategies give a reduction of the total entropy production of 8.7% in the 20-bar case and 4.3% in the 80-bar case. The overall heat transfer coefficient and duty is higher in the 20 bar case which compensates for the increase in entropy production due to a thermal mismatch that is avoided in the 80 bar case. This leads the second law efficiency of the 20 bar case (91%) to be similar to the 80 bar case (89%). We demonstrate that equipartition of the entropy production and equipartition of the thermal driving force are both excellent design principles for the process unit considered with total entropy productions deviating only 0.2% and 0.5% from the state of minimum entropy production. Equipartition of the thermal driving force i.e. a constant difference between the inverse temperatures of the hot and cold layers represents a particularly simple guideline that works remarkably well. We find that both heat transfer and the spin-isomer reaction contribute significantly to the entropy production throughout the length of the process unit. Unlike previous examples in the literature the process unit considered in this work is not characterized by a “reaction mode” at the inlet followed by a “heat transfer mode”. Therefore it does not follow a highway in state space i.e. a band that is particularly dense with energy efficient solutions. By artificially increasing the spin-isomer conversion rate the highway appears when the conversion rate becomes sufficiently high.

This paper summarises the results from a blind-prediction study for models developed for estimating the consequences of vented hydrogen deflagrations. The work is part of the project Improving hydrogen safety for energy applications through pre-normative research on vented deflagrations (HySEA). The scenarios selected for the blind-prediction entailed vented explosions with homogeneous hydrogen-air mixtures in a 20-foot ISO container. The test program included two configurations and six experiments i.e. three repeated tests for each scenario. The comparison between experimental results and model predictions reveals reasonable agreement for some of the models and significant discrepancies for others. It is foreseen that the first blind-prediction study in the HySEA project will motivate developers to improve their models and to update guidelines for users of the models.

Detailed heat exchanger designs are determined by matching intermediate temperatures in a large-scale Claude refrigeration process for liquefaction of hydrogen with a capacity of 125 tons/day. A comparison is made of catalyst filled plate-fin and spiral-wound heat exchangers by use of a flexible and robust modelling framework for multi-stream heat exchangers that incorporates conversion of ortho-to para-hydrogen in the hydrogen feed stream accurate thermophysical models and a distributed resolution of all streams and wall temperatures. Maps of the local exergy destruction in the heat exchangers are presented which enable the identification of several avenues to improve their performances.<br/>The heat exchanger duties vary between 1 and 31 MW and their second law energy efficiencies vary between 72.3% and 96.6%. Due to geometrical constraints imposed by the heat exchanger manufacturers it is necessary to employ between one to four parallel plate-fin heat exchanger modules while it is possible to use single modules in series for the spiral-wound heat exchangers. Due to the lower surface density and heat transfer coefficients in the spiral-wound heat exchangers their weights are 2–14 times higher than those of the plate-fin heat exchangers.<br/>In the first heat exchanger hydrogen feed gas is cooled from ambient temperature to about 120 K by use of a single mixed refrigerant cycle. Here most of the exergy destruction occurs when the high-pressure mixed refrigerant enters the single-phase regime. A dual mixed refrigerant or a cascade process holds the potential to remove a large part of this exergy destruction and improve the efficiency. In many of the heat exchangers uneven local exergy destruction reveals a potential for further optimization of geometrical parameters in combination with process parameters and constraints.<br/>The framework presented makes it possible to compare different sources of exergy destruction on equal terms and enables a qualified specification on the maximum allowed pressure drops in the streams. The mole fraction of para-hydrogen is significantly closer to the equilibrium composition through the entire process for the spiral-wound heat exchangers due to the longer residence time. This reduces the exergy destruction from the conversion of ortho-hydrogen and results in a higher outlet mole fraction of para-hydrogen from the process.<br/>Because of the higher surface densities of the plate-fin heat exchangers they are the preferred technology for hydrogen liquefaction unless a higher conversion to heat exchange ratio is desired.

Hydrogen is a promising carbon-neutral energy carrier for a future decarbonized energy sector. This work presents process simulation studies of the gas switching reforming (GSR) process for hydrogen production with integrated CO₂ capture (GSR-H₂ process) at a minimal energy penalty. Like the conventional steam methane reforming (SMR) process GSR combusts the off-gas fuel from the pressure swing adsorption unit to supply heat to the endothermic reforming reactions. However GSR completes this combustion using the chemical looping combustion mechanism to achieve fuel combustion with CO₂ separation. For this reason the GSR-H₂ plant incurred an energy penalty of only 3.8 %-points relative to the conventional SMR process with 96% CO₂ capture. Further studies showed that the efficiency penalty is reduced to 0.3 %-points by including additional thermal mass in the reactor to maintain a higher reforming temperature thereby facilitating a lower steam to carbon ratio. GSR reactors are standalone bubbling fluidized beds that will be relatively easy to scale up and operate under pressurized conditions and the rest of the process layout uses commercially available technologies. The ability to produce clean hydrogen with no energy penalty combined with this inherent scalability makes the GSR-H2 plant a promising candidate for further research.

Gas switching reforming (GSR) is a promising technology for natural gas reforming with inherent CO₂ capture. Like conventional steam methane reforming (SMR) GSR can be integrated with CO₂ -gas shift and pressure swing adsorption units for pure hydrogen production. The resulting GSR-H2 process concept was techno-economically assessed in this study. Results showed that GSR-H2 can achieve 96% CO₂ capture at a CO₂ avoidance cost of 15 $/ton (including CO₂ transport and storage). Most components of the GSR-H2 process are proven technologies but long-term oxygen carrier stability presents an important technical uncertainty that can adversely affect competitiveness when the material lifetime drops below one year. Relative to the SMR benchmark GSR-H2 replaces some fuel consumption with electricity consumption making it more suitable to regions with higher natural gas prices and lower electricity prices. Some minor alterations to the process configuration can adjust the balance between fuel and electricity consumption to match local market conditions. The most attractive commercialization pathway for the GSR-H2 technology is initial construction without CO2 capture followed by simple retrofitting for CO₂ capture when CO₂ taxes rise and CO₂ transport and storage infrastructure becomes available. These features make the GSR-H2 technology robust to almost any future energy market scenario.

In the event of a fire composite pressure vessels behave very differently from metallic ones: the material is degraded potentially leading to a burst without significant pressure increase. Hence such objects are when necessary protected from fire by using thermally-activated devices (TPRD) and standards require testing cylinder and TPRD together. The pre-normative research project FireComp aimed at understanding better the conditions which may lead to burst through testing and simulation and proposed an alternative way of assessing the fire performance of composite cylinders. This approach is currently used by Air Liquide for the safety of composite bundles carrying large amounts of hydrogen gas.

The fuel quality of hydrogen dispensed from 10 refuelling stations in Europe was assessed. Representative sampling was conducted from the nozzle by use of a sampling adapter allowing to bleed sample gas in parallel while refuelling an FCEV. Samples were split off and distributed to four laboratories for analysis in accordance with ISO 14687 and SAE J2719. The results indicated some inconsistencies between the laboratories but were still conclusive. The fuel quality was generally good. Elevated nitrogen concentrations were detected in two samples but not in violation with the new 300 μmol/mol tolerance limit. Four samples showed water concentrations higher than the 5 μmol/mol tolerance limit estimated by at least one laboratory. The results were ambiguous: none of the four samples showed all laboratories in agreement with the violation. One laboratory reported an elevated oxygen concentration that was not corroborated by the other two laboratories and thus considered an outlier.

Hydrogen is one of the main candidates in replacing fossil fuels in the forthcoming years. However hydrogen technologies must deal with safety aspects due to the specific substance properties. This study aims to provide an overview on the loss of integrity (LOI) of hydrogen equipment which may lead to serious consequences such as fires and explosions. Substantial information regarding the hydrogen lifecycle its properties and safety related aspects has gathered. Furthermore focus has placed on the phenomena responsible for the LOI (e.g. hydrogen embrittlement) and material selection for hydrogen services. Moreover a systematic review on the hydrogen LOI topic has conducted to identify and connect the most relevant and active research group within the topic. In conclusion a significant dearth of knowledge in material behaviour of hydrogen technologies has highlighted. It is thought that is possible to bridge this gap by strengthening the collaborations between scientists from different research fields.

Studies on the prospects of the use of alternative fuels in the maritime industry have rarely been assessed in the context of developing countries. This study assesses seven energy sources for shipping in the context of Bangladesh with a view to ranking their prospects based on sustainability as well as identifying the energy transition criteria. Data were collected from maritime industry experts including seafarers shipping company executives government representatives and academics. The Bayesian Best-Worst Method (BWM) was used for ranking nine criteria related to the suitability and viability of the considered alternative energy sources. Next the PROMETHEE-GAIA method is applied for priority analysis of the seven energy alternatives. The findings reveal that capital cost alternative energy price and safety are the most important factors for alternative energy transition in Bangladesh. Apart from the benchmark HFO Liquified Natural Gas (LNG) HFO-Wind and LNG-Wind hybrids are considered the most viable alternatives. The findings of the study can guide policymakers in Bangladesh in terms of promoting viable energy sources for sustainable shipping.

Alternative fuels are crucial to decarbonize the European maritime transport but their net climate benefits vary with the type of fuel and production country. In this study we assess the energy potential and climate change mitigation benefits of using agricultural and forest residues in different European countries for drop-in (Fast Pyrolysis Hydrothermal Liquefaction and Gasification to Fischer-Tropsch fuels or Bio-Synthetic Natural Gas) and hydrogen-based biofuels (hydrogen ammonia and methanol) with or without carbon capture and storage (CCS). Our results show the combinations of countries and biofuel options that successfully achieve the decarbonization targets set by the FuelEU Maritime initiative for the next years including a prospective analysis that include technological changes projected for the biofuel supply chains until 2050. With the current technologies the largest greenhouse gas (GHG) mitigation potential per year at a European scale is obtained with bio-synthetic natural gas and hydrothermal liquefaction. Among carbon-free biofuels ammonia currently has higher mitigation but hydrogen can achieve a lower GHG intensity per unit of energy with the projected decarbonization of the electricity mixes until 2050. The full deployment of CCS can further accelerate the decarbonization of the maritime sector. Choosing the most suitable renewable fuels requires a regional perspective and a transition roadmap where countries coordinate actions to meet ambitious climate targets.

International standards related to cryogenic hydrogen transferring technologies for mobile applications (filling of trucks ships stationary tanks) are missing and there is lack of experience. The European project ELVHYS (Enhancing safety of liquid and vaporized hydrogen transfer technologies in public areas for mobile applications) aims to provide indications on inherently safer and efficient cryogenic hydrogen technologies and protocols in mobile applications by proposing innovative safety strategies which are the results of a detailed risk analysis. This is carried out by applying an inter-disciplinary approach to study both the cryogenic hydrogen transferring procedures and the phenomena that may arise from the loss of containment of a piece of equipment containing hydrogen. ELVHYS will provide critical inputs for the development of international standards by creating inherently safer and optimized procedures and guidelines for cryogenic hydrogen transferring technologies thus increasing their safety level and efficiency. The aim of this paper is twofold: present the state of the art of liquid hydrogen transfer technologies by focusing on previous research projects such as PRESLHY and introduce the objectives and methods planned in the new EU project ELVHYS.

This paper compares six (6) alternatives for green hydrogen transport at sea. Two (2) alternatives of liquid hydrogen (LH2) by ship two (2) alternatives of compressed hydrogen (cH2) by ship and two (2) alternatives of hydrogen by pipeline. The ship alternatives study having hydrogen storage media at both end terminals to reduce the ships’ time at port or prescinding of them and reduce the immobilized capital. In the case of the pipeline new models are proposed by considering pressure costs. One scenario considers that there are compression stations every 500 km and the other one considers that there are none along the way. These alternatives are assessed under nine different scenarios that combine three distances: 100 km 2500 km and 5000 km; and three export rates of hydrogen 100 kt/y 1 Mt/y and 10 Mt/y. The results show including uncertainty bands that for the 100 km of distance the best alternative is the pipeline. For 2500 km and 100 kt/y the top alternative is cH2 shipping without storage facilities at the port terminals. For 2500 km and 1 Mt/y and for 5000 km and 100 kt/y the best alternatives are cH2 or LH2 shipping. For the remaining scenarios the best alternative is LH2 shipping.

Green hydrogen could play a crucial role in the maritime industry’s journey towards decarbonization. Produced through electrolysis hydrogen is emission free and could be widely available across the globe in future – as a marine fuel or a key enabler for synthetic fuels. Many in shipping recognize hydrogen’s potential as a fuel but the barriers to realizing this potential are substantial.<br/>The 1st Edition of the ‘Handbook for Hydrogen-fuelled Vessels’ offers a road map towards safe hydrogen operations using fuel cells. It details how to navigate the complex requirements for design and construction and it covers the most important aspects of hydrogen operations such as safety and risk mitigation engineering details for hydrogen systems and implementation phases for maritime applications based on the current regulatory Alternative Design process framework.<br/>This publication is the result of the 1st phase of the DNV-led Joint Industry Project MarHySafe which has brought together a consortium of 26 leading company and associations. The project is ongoing and this publication will be continually updated to reflect the latest industry expertise on hydrogen as ship fuel.

In this research we conducted water electrolysis experiments of a carbon black (CB) based sodium sulfate electrolyte using a Hoffman voltameter. The main objective was to investigate hydrogen production in such systems as well as analyse the electrical properties and thermal properties of nanofluids. A halogen lamp mimicking solar energy was used as a radiation source and a group of comparative tests were also conducted with different irradiation areas. The results showed that by using CB and light it was possible to increase the hydrogen production rate. The optimal CB concentration was 0.1 wt %. At this concentration the hydrogen production rate increased by 30.37% after 20 min of electrolysis. Hence we show that using CB in electrolytes irradiated by solar energy could save the electrical energy necessary for electrolysis processes.

Steam methane reforming with CO2 capture (blue hydrogen) and water electrolysis based on renewable electricity (green hydrogen) are commonly assumed to be the main supply options in a future hydrogen economy. However another promising method is emerging in the form of natural gas pyrolysis (turquoise hydrogen) with pure carbon as a valuable by-product. To better understand the potential of turquoise hydrogen this study presents a techno-economic assessment of a molten salt pyrolysis process. Results show that moderate reactor pressures around 12 bar are optimal and that reactor size must be limited by accepting reactor performance well below the thermodynamic equilibrium. Despite this challenge stemming from slow reaction rates the simplicity of the molten salt pyrolysis process delivers high efficiencies and promising economics. In the long-term carbon could be produced for 200–300 €/ton granting access to high-volume markets in the metallurgical and chemical process industries. Such a scenario makes turquoise hydrogen a promising alternative to blue hydrogen in regions with public resistance to CO2 transport and storage. In the medium-term expensive first-of-a-kind plants could produce carbon around 400 €/ton if hydrogen prices are set by conventional blue hydrogen production. Pure carbon at this cost level can access smaller high-value markets such as carbon anodes and graphite ensuring profitable operation even for first movers. In conclusion the economic potential of molten salt pyrolysis is high and further demonstration and scale-up efforts are strongly recommended.

Worldwide energy systems are experiencing a transition to more sustainable systems. According to the Hydrogen Roadmap Europe (FCH EU 2019) hydrogen will play an important role in future energy systems due to its ability to support sustainability goals and will account for approximately 13% of the total energy mix in the coming future. Correct hydrogen supply chain (HSC) planning is therefore vital to enable a sustainable transition. However due to the operational characteristics of the HSC its planning is complicated. Renewable hydrogen supply can be diverse: Hydrogen can be produced de-centrally with renewables such as wind and solar energy or centrally by using electricity generated from a hydro power plant with a large volume. Similarly demand for hydrogen can also be diverse with many new applications such as fuels for fuel cell electrical vehicles and electricity generation feedstocks in industrial processes and heating for buildings. The HSC consists of various stages (production storage distribution and applications) in different forms with strong interdependencies which further increase HSC complexity. Finally planning of an HSC depends on the status of hydrogen adoption and market development and on how mature technologies are and both factors are characterised by high uncertainties. Directly adapting the traditional approaches of supply chain planning for HSCs is insufficient. Therefore in this study we develop a planning matrix with related planning tasks leveraging a systematic literature review to cope with the characteristics of HSCs. We focus only on renewable hydrogen due to its relevance to the future low-carbon economy. Furthermore we outline an agenda for future research from the supply chain management perspective in order to support HSC development considering the different phases of HSCs adoption and market development.

Smooth power injection is one of the possible services that modern wind farms could provide in the not-so-far future for which energy storage is required. Indeed this is one among the three possible operations identified by the International Energy Agency (IEA)-Hydrogen Implementing Agreement (HIA) within the Task 24 final report that may promote their integration into the main grid in particular when paired to hydrogen-based energy storages. In general energy storage can mitigate the inherent unpredictability of wind generation providing that they are deployed with appropriate control algorithms. On the contrary in the case of no storage wind farm operations would be strongly affected as well as their economic performances since the penalty fees wind farm owners/operators incur in case of mismatches between the contracted power and that actually delivered. This paper proposes a Model Predictive Control (MPC) algorithm that operates a Hydrogen-based Energy Storage System (HESS) consisting of one electrolyzer one fuel cell and one tank paired to a wind farm committed to smooth power injection into the grid. The MPC relies on Mixed-Logic Dynamic (MLD) models of the electrolyzer and the fuel cell in order to leverage their advanced features and handles appropriate cost functions in order to account for the operating costs the potential value of hydrogen as a fuel and the penalty fee mechanism that may negatively affect the expected profits generated by the injection of smooth power. Numerical simulations are conducted by considering wind generation profiles from a real wind farm in the center-south of Italy and spot prices according to the corresponding market zone. The results show the impact of each cost term on the performances of the controller and how they can be effectively combined in order to achieve some reasonable trade-off. In particular it is highlighted that a static choice of the corresponding weights can lead to not very effective handling of the effects given by the combination of the system conditions with the various exogenous’ while a dynamic choice may suit the purpose instead. Moreover the simulations show that the developed models and the set-up mathematical program can be fruitfully leveraged for inferring indications on the devices’ sizing.