Norway

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.

This article presents findings from a representative survey fielded through the Norwegian Citizen Panel examining public perceptions of hydrogen fuel and its different production methods. Although several countries including Norway have strategies to increase the production of hydrogen fuel our results indicate that hydrogen as an energy carrier and its different production methods are still unknown to a large part of the public. A common misunderstanding seems to be confusing ‘hydrogen fuel’ in general with environmentally friendly ‘green hydrogen’. Results from a survey experiment (N = 1906) show that production method is important for public acceptance. On a five-point acceptance scale respondents score on average 3.9 for ‘green’ hydrogen which is produced from renewable energy sources. The level of acceptance is significantly lower for ‘blue’ (3.2) and ‘grey’ (2.3) hydrogen when respondents are informed that these are produced from coal oil or natural gas. Public support for hydrogen fuel in general as well as the different production methods is also related to their level of worry about climate change gender and political affiliation. Widespread misunderstandings regarding ‘green’ hydrogen production could potentially fuel public resistance as new ‘blue’ or ‘grey’ projects develop. Our results indicate a need for clearer communication from the government and developers regarding production methods to avoid distrust and potential public backfire.

Norwegian offshore wind farms may be able to supply power to offshore oil and gas platforms in the near future thanks to the expeditious development of offshore wind technology. This would result in a reduction in CO2 emissions from oil and gas offshore installations which are currently powered predominantly by gas turbines. The challenge with using wind power is that offshore oil and gas installations require a fairly constant and stable source of power whereas wind power typically exhibits significant fluctuations over time. The purpose of this study is to perform a technical feasibility evaluation of using wind power to supply an offshore oil and gas installation on the basis of dynamic process simulations. Throughout the study only the topside processing system is considered since it is the most energy-intensive part of an oil and gas facility. An offshore field on the Norwegian Continental Shelf is used as a case study. The results indicate that when the processing system operates in steady-state conditions it cannot be powered solely by wind energy and another power source is required to compensate for low wind power generation intervals. An alternative would be to store wind energy during periods of high generation (e.g. by producing hydrogen or ammonia) and use it during periods of low generation. Utilizing energy storage methods wind energy can be continuously used for longer periods of time and provide a suitable constant power source for the studied case. Higher constant power can also be provided by increasing the efficiency of energy recovery and storage processes. Alternatively these two technologies may be integrated with gas turbines if the required storage cannot be provided or higher power is required. It was estimated that the integration of wind energy could result in noticeable reductions in CO2 emissions for the case study. Additionally according to the results the production storage and reuse of hydrogen and ammonia on-site may be viable options for supplying power.

Hydrogen will be a central cross-sectoral energy carrier in the decarbonization of the European energy system. This paper investigates how a large-scale deployment of green hydrogen production affects the investments in transmission and generation towards 2060 analyzes the North Sea area with the main offshore wind projects and assesses the development of an offshore energy hub. Results indicate that the hydrogen deployment has a tremendous impact on the grid development in Europe and in the North Sea. Findings indicate that total power generation capacity increases around 50%. The offshore energy hub acts mainly as a power transmission asset leads to a reduction in total generation capacity and is central to unlock the offshore wind potential in the North Sea. The effect of hydrogen deployment on power prices is multifaceted. In regions where power prices have typically been lower than elsewhere in Europe it is observed that hydrogen increases the power price considerably. However as hydrogen flexibility relieves stress in high-demand periods for the grid power prices decrease in average for some countries. This suggests that while the deployment of green hydrogen will lead to a significant increase in power demand power prices will not necessarily experience a large increase.

Hydrogen is a clean substitute for hydrocarbon fuels in the marine sector. Liquid hydrogen (2 ) can be used to move and store large amounts of hydrogen. This novel application needs further study to assess the potential risk and safety operation. A recent study of 2 large-scale release tests was conducted to replicate spills of 2 inside the ship’s tank connection space and during bunkering operations. The tests were performed in a closed and outdoor facility. The 2 spills can lead to detonation representing a safety concern. This study analyzed the aforementioned 2 experiments and proposed a novel application of the random forests algorithm to predict the oxygen phase change and to estimate whether the hydrogen concentration is above the lower flammability limit (LFL). The models show accurate predictions in different experimental conditions. The findings can be used to select reliable safety barriers and effective risk reduction measures in 2 spills.

Ambitious decarbonization pathways to limit the global temperature rise to well below 2 ◦C will require largescale CO2 removal from the atmosphere. One promising avenue for achieving this goal is hydrogen production from biomass with CO2 capture. The present study investigates the techno-economic prospects of a novel biomass-to-hydrogen process configuration based on the gas switching integrated gasification (GSIG) concept. GSIG applies the gas switching combustion principle to indirectly combust off-gas fuel from the pressure swing adsorption unit in tubular reactors integrated into the gasifier to improve efficiency and CO2 capture. In this study these efficiency gains facilitated a 5% reduction in the levelized cost of hydrogen (LCOH) relative to conventional O2-blown fluidized bed gasification with pre-combustion CO2 capture even though the larger and more complex gasifier cancelled out the capital cost savings from avoiding the air separation and CO2 capture units. The economic assessment also demonstrated that advanced gas treatment using a tar cracker instead of a direct water wash can further reduce the LCOH by 12% and that the CO2 prices in excess of 100 €/ton consistent with ambitious decarbonization pathways will make this negative-emission technology economically highly attractive. Based on these results further research into the GSIG concept to facilitate more efficient utilization of limited biomass resources can be recommended.

Automotive proton-exchange membrane fuel cells (PEMFCs) have finally reached a state of technological readiness where several major automotive companies are commercially leasing and selling fuel cell electric vehicles including Toyota Honda and Hyundai. These now claim vehicle speed and acceleration refueling time driving range and durability that rival conventional internal combustion engines and in most cases outperform battery electric vehicles. The residual challenges and areas of improvement which remain for PEMFCs are performance at high current density durability and cost. These are expected to be resolved over the coming decade while hydrogen infrastructure needs to become widely available. Here we briefly discuss the status of automotive PEMFCs misconceptions about the barriers that platinum usage creates and the remaining hurdles for the technology to become broadly accepted and implemented.

Globally the accelerating use of renewable energy sources enabled by increased efficiencies and reduced costs and driven by the need to mitigate the effects of climate change has significantly increased research in the areas of renewable energy production storage distribution and end-use. Central to this discussion is the use of hydrogen as a clean efficient energy vector for energy storage. This review by experts of Task 32 “Hydrogen-based Energy Storage” of the International Energy Agency Hydrogen TCP reports on the development over the last 6 years of hydrogen storage materials methods and techniques including electrochemical and thermal storage systems. An overview is given on the background to the various methods the current state of development and the future prospects. The following areas are covered; porous materials liquid hydrogen carriers complex hydrides intermetallic hydrides electro-chemical storage of energy thermal energy storage hydrogen energy systems and an outlook is presented for future prospects and research on hydrogen-based energy storage

The reduction of greenhouse gas emissions has entered regulatory agendas in shipping. In Norway a debate has been ongoing for over a decade about whether liquefied natural gas (LNG) ship fuel enables or impedes the transition to a greener future for shipping. This paper explores the assembling of ship fuel before and after the introduction of a controversial carbon tax on LNG. It reconstructs how changes in the regulatory apparatus prompted the reworking of natural gas into a ship fuel yet later slowed down the development of LNG in a strategy to promote alternative zero-emission fuels such as hydrogen. Following ship fuel as socio-materiality in motion we find that fossil fuels are reworked into new modes of application as part of transition policies. Natural gas continues to be enacted as an “enabler of transition” in the context of shipping given that current government policies work to support the production of hydrogen from natural gas and carbon capture and storage (CCS). New modes of accounting for emissions reassemble existing fossil fuel materiality by means of CCS and fossil-based zero-emission fuels. We examine retrofit as a particular kind of reassembling and as a prism for studying the politics of fuel and the relation between transitions and existing infrastructures.

An opportunity to decarbonise the offshore oil and gas sector lies in the integration of renewable energy sources with energy storage in a hybrid energy system (HES). Such concept enables maximising the exploitation of carbon-free renewable power while minimising the emissions associated with conventional power generation systems such as gas turbines. Offshore plants in addition to electrical and mechanical power also require process heat for their operation. Solutions that provide low-emission heat in parallel to power are necessary to reach a very high degree of decarbonisation. This paper investigates different options to supply process heat in offshore HES while the electric power is mostly covered by a wind turbine. All HES configurations include energy storage in the form of hydrogen tied to proton exchange membrane (PEM) electrolysers and fuel cells stacks. As a basis for comparison a standard configuration relying solely on a gas turbine and a waste heat recovery unit is considered. A HES combined with a waste heat recovery unit to supply heat proved efficient when low renewable power capacity is integrated but unable to deliver a total CO2 emission reduction higher than around 40%. Alternative configurations such as the utilization of gas-fired or electric heaters become more competitive at large installed renewable capacity approaching CO2 emission reductions of up to 80%.