Norway

Hydrogen-microvoid interactions were studied via unit cell analyses with different hydrogen concentrations. The absolute failure strain decreases with hydrogen concentration but the failure loci were found to follow the same trend dependent only on stress triaxiality in other words the effects of geometric constraint and hydrogen on failure are decoupled. Guided by the decoupling principle a hydrogen informed Gurson model is proposed. This model is the first practical hydrogen embrittlement simulation tool based on the hydrogen enhanced localized plasticity (HELP) mechanism. It introduces only one additional hydrogen related parameter into the Gurson model and is able to capture hydrogen enhanced internal necking failure of microvoids with accuracy; its parameter calibration procedure is straightforward and cost efficient for engineering purpose

By adding energy as hydrogen to the biomass-to-liquid (BtL) process several published studies have shown that carbon efficiency can be increased substantially. Hydrogen can be produced from renewable electrical energy through the electrolysis of water or steam. Adding high-temperature thermal energy to the gasifier will also increase the overall carbon efficiency. Here an economic criterion is applied to find the optimal distribution of adding electrical energy directly to the gasifier as opposed to the electrolysis unit. Three different technologies for electrolysis are applied: solid oxide steam electrolysis (SOEC) alkaline water electrolysis (AEL) and proton exchange membrane (PEM). It is shown that the addition of part of the renewable energy to the gasifier using electric heaters is always beneficial and that the electrolysis unit operating costs are a significant portion of the costs. With renewable electricity supplied at a cost of 50 USD/MWh and a capital cost of 1500 USD/kW installed SOEC the operating costs of electric heaters and SOEC account for more than 70% of the total costs. The energy efficiency of the electrolyzer is found to be more important than the capital cost. The optimal amount of energy added to the gasifier is about 37–39% of the energy in the biomass feed. A BtL process using renewable hydrogen imports at 2.5 USD/kg H2 or SOEC for hydrogen production at reduced electricity prices gives the best values for the economic objective.

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.

This paper describes two models for analysing and simulating the physical effects of explosive phase transition of liquid hydrogen (LH2) also known as cold BLEVE. The present work is based on theoretical and experimental work for liquefied CO2. A Rankine Hugoniot analysis for evaporation waves that was previously developed for CO2 is now extended to LH2. A CFD-method for simulating two-phase flow with mass transfer between the phases is presented and compared with the Rankine Hugoniot analysis results. The Rankine Hugoniot method uses real fluid equations of state suited for LH2 while the CFD method uses linear equations of state suited for shock capturing methods. The results show that there will be a blast from a catastrophic rupture of an LH2 vessel and that the blast waves will experience a slow decay due to the large positive pressure phase.

This paper evaluates the potential of grid services in France Italy Norway and Spain to provide an alternative income for electrolysers producing hydrogen from wind power. Grid services are simulated with each country's data for 2017 for energy prices grid services and wind power profiles from relevant wind parks. A novel metric is presented the value of curtailed hydrogen which is independent from several highly uncertain parameters such as electrolyser cost or hydrogen market price. Results indicate that grid services can monetise the unused spare capacity of electrolyser plants improving their economy in the critical deployment phase. For most countries up-regulation yields a value of curtailed hydrogen above 6 V/kg over 3 times higher than the EU's 2030 price target (without incentives). However countries with large hydro power resources such as Norway yield far lower results below 2 V/kg. The value of curtailed hydrogen also decreases with hydrogen production corresponding to the cases of symmetric and down-regulation.

Is there a place for today’s fossil fuel exporters in a low-carbon future? This study explores trade channels between energy exporters and importers using a novel electricity-hydrogen-steel energy systems model calibrated to Norway a major natural gas producer and Germany a major energy consumer. Under tight emission constraints Norway can supply Germany with electricity (blue) hydrogen or natural gas with re-import of captured CO2. Alternatively it can use hydrogen to produce steel through direct reduction and supply it to the world market an export route not available to other energy carriers due to high transport costs. Although results show that natural gas imports with CO2 capture in Germany is the least-cost solution avoiding local CO2 handling via imports of blue hydrogen (direct or embodied in steel) involves only moderately higher costs. A robust hydrogen demand would allow Norway to profitably export all its natural gas production as blue hydrogen. However diversification into local steel production as one example of easy-to-export industrial base products offers an effective hedge against the possibility of lower European blue hydrogen demand. Looking beyond Europe the findings of this study are also relevant for the world’s largest energy exporters (e.g. OPEC+) and importers (e.g. developing Asia). Thus it is recommended that large hydrocarbon exporters consider a strategic energy export transition to a diversified mix of blue hydrogen and climate-neutral industrial base products.

Economical offshore wind developments depend on alternatives for cost-efficient transmission of the generated energy to connecting markets. Distance to shore availability of an offshore power grid and scale of the wind farm may impede export through power cables. Conversion to H2 through offshore electrolysis may for certain offshore wind assets be a future option to enable energy export. Here we analyse the cost sensitivity of offshore electrolysis for harvesting offshore wind in the North Sea using a technology-detailed multi-carrier energy system modelling framework for analysis of energy export. We include multiple investment options for electric power and hydrogen export including HVDC cables new hydrogen pipelines tie-in to existing pipelines and pipelines with linepacking. Existing hydropower is included in the modelling and the effect on offshore electrolysis from increased pumping capacity in the hydropower system is analysed. Considering the lack of empirical cost data on offshore electrolysis as well as the high uncertainty in future electricity and H2 prices we analyse the cost sensitivity of offshore electrolysis in the North Sea by comparing costs relative to onshore electrolysis and energy prices relative to a nominal scenario. Offshore electrolysis is shown to be particularly sensitive to the electricity price and an electricity price of 1.5 times the baseline assumption was needed to provide sufficient offshore energy for any significant offshore electrolysis investments. On the other hand too high electricity prices would have a negative impact on offshore electrolysis because the energy is more valuable as electricity even at the cost of increased wind power curtailment. This shows that there is a window-of-opportunity in terms of onshore electricity where offshore electrolysis can play a significant role in the production of H2 . Pumped hydropower increases the maximum installed offshore electrolysis at the optimal electricity and H2 prices and makes offshore electrolysis more competitive at low electricity prices. Linepacking can make offshore electrolysis investments more robust against low H2 and high electricity prices as it allow for more variable H2 production through storing excess energy from offshore. The increased electrolysis capacity needed for variable electrolyser operation and linepacking is installed onshore due to its lower CAPEX compared to offshore installations.

Throughout the history of the mining petroleum process and nuclear industries continuous efforts have been made to develop and improve measures to prevent and mitigate accidental explosions. Over the coming decades energy systems are expected to undergo a transition towards sustainable use of conventional hydrocarbons and an increasing share of renewable energy sources in the global energy mix. The variable and intermittent supply of energy from solar and wind points to energy systems based on hydrogen or hydrogen-based fuels as the primary energy carriers. However the safety-related properties of hydrogen imply that it is not straightforward to achieve and document the same level of safety for hydrogen systems compared to similar systems based on established fuels such as petrol diesel and natural gas. Compared to the conventional fuels hydrogen-air mixtures have lower ignition energy higher combustion reactivity and a propensity to undergo deflagration-to-detonation-transition (DDT) under certain conditions. To achieve an acceptable level of safety it is essential to develop effective measures for mitigating the consequences of hydrogen explosions in systems with certain degree of congestion and confinement. Extensive research over the last decade have demonstrated that chemical inhibition or partial suppression can be used for mitigating the consequences of vapour cloud explosions (VCEs) in congested process plants. Total and cooperation partners have demonstrated that solid flame inhibitors injected into flammable hydrocarbon-air clouds represent an effective means of mitigating the consequences of VCEs involving hydrocarbons. For hydrogen-air explosions these same chemicals inhibitors have not proved effective. It is however well-known that hydrocarbons can affect the burning velocity of hydrogen-air mixtures greatly. This paper gives an overview over previous work on chemical inhibitors. In addition experiments in a 20-litre vessel have been performed to investigate the effect of combinations of hydrocarbons and alkali salts on hydrogen/air mixtures.

Accurate estimation of mass flow rate and release conditions is important for the design of dispersion and combustion experiments for the subsequent validation of CFD codes/models for consequence assessment analysis within related risk assessment studies and for associated Regulation Codes and Standards development. This work focuses on the modelling of the discharge phase of the recent large scale LH2 release and dispersion experiments performed by HSE within the framework of PRESLHY project. The experimental conditions covered sub-cooled liquid stagnation conditions at two pressures (2 and 6 bara) and 3 release nozzle diameters (1 ½ and ¼ inches). The simulations were performed using a 1d engineering tool which accounts for discharge line effects due to friction extra resistance due to fittings and area change. The engineering tool uses the Possible Impossible Flow (PIF) algorithm for choked flow calculations and the Helmholtz Free Energy (HFE) EoS formulation. Three different phase distribution models were applied. The predictions are compared against measured and derived data from the experiments and recommendations are given both regarding engineering tool applicability and future experimental design.

A process where power and biomass are converted to Fischer-Tropsch liquid fuels (PBtL) is compared to a conventional Biomass-to-Liquid (BtL) process concept. Based on detailed process models it is demonstrated that the carbon efficiency of a conventional Biomass to Liquid process can be increased from 38 to more than 90% by adding hydrogen from renewable energy sources. This means that the amount of fuel can be increased by a factor of 2.4 with the same amount of biomass. Electrical power is applied to split water/steam at high temperature over solid oxide electrolysis cells (SOEC). This technology is selected because part of the required energy can be replaced by available heat. The required electrical power for the extra production is estimated to be 11.6 kWh per liter syncrude (C ) 5+ . By operating the SOEC iso-thermally close to 850 °C the electric energy may be reduced to 9.5 kWh per liter which is close to the energy density of jet fuel. A techno-economic analysis is performed where the total investments and operating costs are compared for the BtL and PBtL. With an electrical power price of 0.05 $/kWh and with SOEC investment cost of the 1000 $/kW(el) the levelized cost of producing advanced biofuel with the PBtL concept is 1.7 $/liter which is approximately 30% lower than for the conventional BtL. Converting excess renewable electric power to advanced biofuel in a PBtL plant is a sensible way of storing energy as a fuel with a relatively high energy density.