Publishable summary: This deliverable focus on the basic technical evaluation of symbiosis option and a study on managerial, business and legal issues via various potential use cases within the industrial area of Linz with the main players voestalpine Stahl Linz GmbH, operating an integrated steel mill and Borealis Agromelamine Linz GmbH an ammonia-based fertilizer production site. A theoretical evaluation of technical options for IS at different TRL was performed with the main objectives to identify technically applicable and economically favorable valorization options of renewable hydrogen. Overriding objectives here concern:
• Evaluation of possible cooperation in the field of gases and energy exchange
• Theoretically explore the substitution potential of actual energy vector demands via renewable hydrogen & synthetic natural gas
• Minimize cost structures for renewable energy supply and storage
• Increase the security of supply for renewable energy provision (predominantly H2) for the on-site productions
• Maximize primary energy efficiency and GHG savings via symbiotic valorization of renewable hydrogen
• Study potential system integration of ammonia-based hydrogen route in chemicals and iron and steel production
The predominant focus is on the potential symbiotic valorisation of renewable hydrogen in general but in order to facilitate the application of the symbiosis case, technical options at different technology readiness levels (TRL) levels like:
• direct renewable hydrogen exchange from existing water electrolysis capacities,
• methanation of SMR and power plant CO2 off-gases to provide natural gas substitute,
• methanation of steel gases for natural gas substitute,
• utilisation of coke oven gas as substitute for H2 in ammonia production,
• (reversible) haber bosch synthesis for H2 storage via NH3 and reconversion
• Utilization of CO2 for downstream production
• process integration of existing and potential new assets
Numerous on-site assessments have been carried out in Task 8.2. A large number of scenarios had to be developed to represent the many possible combinations of plant and energy flows. Executed assessments are used to identify promising options for realization and relevant dimensions in terms of technical, economic and managerial dimensions are elaborated within a specific task force formed by partners of the CORALIS follower case Linz (LAT Nitrogen (formerly Borealis Agrolinz Melamine), voestalpine steel, Energieinstitut an der JKU Linz, K1-MET). Therefore, several meetings and workshops have been realized in order to develop the industrial symbiosis case, to launch different activities and to establish recurrent meetings that allow smooth communication within the industrial partners in Linz. Form the first meeting in November 2020 to the meetings in summer 2022 all potential use cases were developed, discussed and refined.
In the following, the key results of the use cases 1 to 7 are summarized.
Use case 1: Direct renewable H2 exchange from existing water electrolysis capacities
Use case 1.1 was extended to five sub-cases, which are more complex than the original idea to further utilize an existing water electrolysis of 6 MWel at voestalpine Stahl GmbH in Linz (VAS). The option to use green hydrogen as an input of LAT Nitrogen’s (LAT, formerly known as Borealis Agrolinz Melamine, short BAM) ammonia production was simulated, with very positive results. The current grey hydrogen from natural gas steam methane reformer could be replaced in principle 1:1 with renewable external H2 from water electrolysis with several positive effects in regard to CO2 emissions and waste heat production. However, only a maximum share of 15 % external H2 allows to keep the flue gas temperature profile in the convection bank at the normal operating point. Thus, further technical analysis on this issue might be needed.
Use case 1.2 analyzed how much hydrogen could be provided to LAT by the existing 6 MWel unit, which theoretically produces about 8 Mio m³ H2 per year. Thus, in use case 1.3 the expansion of the electrolyzing capacities by a 60 MWel PEMEC was further analyzed: about 80 Mio m³ H2 could be produced annually and replace roughly half the amount of natural gas, i.e., about 7 % of LAT’s demand, considering also the 6 MW electrolyzer, about 8 % could theoretically be replaced. However, a future demand by VAS is not considered in these calculations.
In use case 1.4 a future scenario regarding the further decarbonization of LAT’s and especially VAS’ processes was analyzed, with the result that the annual hydrogen demand of both companies in Linz is enormous and about 4,301 Mio m³, the power of the required electrolyzing capacity is about 3,250 MW resulting in an electricity consumption of 23 TWh/a.
As a local production of green hydrogen in this extent is likely to be not achievable for several reasons, use case 1 to 5 and especially the BM development and literature research focused on import strategies, in combination with local production.
Use case 2: Methanation of CO2 to produce SNG
For use case 2 an Aspen simulation of a local “carbon cycle” with a subsequent TEA was conducted. Based on the CO2 available in the off streams of LAT and VAS, theoretically, way more SNG could be produced than needed, however, the availability of hydrogen is the limiting factor. The results of the Aspen simulation however in regard to process parameters and design are promising. The subsequent LCoE calculation found that when a complete plant (on-site electrolysis with downstream methanation) installed, the SNG production costs are around 6 to 26 €-cent/kWh, depending mainly on the electricity costs for the electrolysis. Further, it should be noted, however, that the use of the by-products – heat and oxygen – is essential for reducing the SNG production costs. If hydrogen is not produced on site but imported, only the methanation plant is required at the site. When only the methanation unit is located in Linz, the SNG production costs also range from about 6 to 26 cent/kWh, largely determined by hydrogen import costs. Also, the sale of by-products is limited to the utilisation of heat from the methanation plant as local structures could hardly cope with these orders of magnitude.
Use case 3: Methanation of off gases from the integrated steel plant
In this use case, the BFG and BOFG are considered, the COG is discussed in use case 4. In the methanation unit CO2 and CO react to CH4. It was assumed that the required green hydrogen will be provided by electrolyzer capacities. Previous experimental studies have shown that in principle methanation of BFG and BOFG is technically possible without the separation of the inert gas nitrogen. Therefore, a product gas composed of 51.5 % CH4 and 48.5 % N2 could be generated for further utilization.
The amount of gas needed to compensate the loss of the internal use of the steel gases was calculated on basis of the heating values according to the gas composition. Furthermore, the produced gas mixture can theoretically be considered as feedstock in the facilities of LAT since nitrogen is needed for ammonia synthesis anyway. If the overproduced gas should be sold to the grid a separation of methane and nitrogen is necessary, to meet the requirements of the Austrian natural gas grid qualities. Currently no solutions are on the market that can economically separate such large amounts of nitrogen from the resulting gas mixture. However, this was a very theoretical use case, which would have to be subjected to a more detailed technical examination.
In order to methanize the total amount of steel gases about 11,353 Mio. Nm³ H2 are needed. The output are about 3,350 Mio. Nm³ of SNG. If the H2 is produced on-site, an electrolyzer with a nominal electric power of about 7.5 GW is required. The renewable electricity demand is about 60 TWh. In addition to the electrolysis plant, the downstream methanation plant has a nominal power of about 4.6 GW. The cost are equal to the costs in use case 2, since the costs only differ due to scaling of the plant. Here, too, the resulting estimates are very far away from realistic orders of magnitude in technical realizations in the medium term.
Use case 4: Utilization from coke oven gas for H2 supply
COG is rich in H2 (and CH4) and is therefore a valuable gas for the chemical industry. This use case looked into two sub-cases: 4.1 direct usage of COG in the existing ammonia plant; 4.2 methanation of COG before utilization.
In use case 4.1 the same Aspen Plus model as for use case 1.1 “Renewable H2 addition to LAT ammonia production plants” was used to simulate the options. The COG implies a reduction in the NG consumption and the CO2 emissions, since less H2 needs to be produced in the SMR units. As main results the following was found: the best tie-in points are the primary reformer and the desulfurization reactor; however, both are limited by the temperatures in the convection bank. Also, the full amount of COG of VAS can be processed at LAT, since the gas composition is roughly comparable to the process gas between primary and secondary reformer. This means that COG theoretically replaces 43 wt% of the current NG demand. However, the synergies are limited, because the COG used for ammonia production is missing at the power plant of VAS, which means the capacities have to be compensated somehow. Furthermore, if the decarbonization of the steel industry proceeds, the COG might not be available in the long term.
Regarding use case 4.2, COG generally contains sizeable amounts of nitrogen. Due to the large amounts of water formed and separated in the methanation reaction the nitrogen content is further increased in the finished product. Natural gas containing nitrogen is problematic for grid injection and may also lead to difficulties in further industrial use. Thus, it would be beneficial if the nitrogen content of the SNG does not need to be removed before injection into the Haber-Bosch process. Therefore, the influence of an increasing nitrogen load in the reformer natural gas feed, was studied. The simulation was based on the Aspen Plus used for use case 2. It is concluded that a complete exchange of external natural gas with natural gas from methanation with COG as hydrogen source is not only tolerable, but has considerable advantages concerning feed requirements, such as H2 loss, recycle gas volume and reaction pressure. However, similarly to use case 4.1, the synergies are limited, because the COG used for ammonia production is missing at the power plant of VAS, which means the capacities have to be compensated somehow. Furthermore, if the decarbonization of the steel industry proceeds, the COG might not be available in the long term.
Use case 5: H2 storage as ammonia and reconversion on demand
For this use case, a detailed simulation and technoeconomic study was conducted by the sub-contractor Technical University of Vienna, Institute of Energy Systems and Thermodynamics and Institute of Process Engineering. The focus was on 1) green Haber-Bosch-Synthesis, 2) decomposition of ammonia, 3) gas purification (separation of N2/H2 from ammonia) green Haber-Bosch-Synthesis: In the fossil-fueled hydrogen production process, several impurities remain in the input streams. Thus, purging the stream is necessary to avoid accumulation of these contaminants in the process. For the green route, the purge stream and hydrogen recycle are no longer necessary. In this work, the influence of the absence of certain impurities in reactants on the synthesis of Borealis´ actual plant was evaluated. In terms of energy input and output, not much changes except the elimination of the purge. In the input streams there is CH4 which leads to a decreased LHV. Compression energy could be reduced because the absolute reactor pressure was decreased. Recompression stays nearly the same. Generally, cooling can be reduced.
The produced ammonia is stored under pressure as liquid ammonia. In order to utilize the hydrogen, the ammonia has to decompose into hydrogen and nitrogen. The decomposition is an endothermic reaction and produces an increased number of molecules. The decomposition was calculated for different H2 application routes. One possible application is utilizing H2 in the steel annealing process at VAS. Another possible application is for the direct reduction of iron at VAS.
After the decomposition of ammonia, hydrogen and nitrogen need to be separated. Possible purification steps are stripping, cool drying, absorption, adsorption, and membrane separation. Ammonia scrubbing and membrane separation were more closely looked at in the analysis.
As shown in the synthesis simulation, considerable energy savings can be expected in synthesis, mainly, as no purge is needed, the pressure in the reactor is reduced and there is a smaller recycle stream. Future investigations should look at a more detailed modeling of the reaction. To achieve the requirements given for the H2 application in steel annealing, no H2 and N2 separation via membrane is necessary. If acid scrubbing is chosen as NH3 removal step, subsequent drying is required. Alternatively, an adsorptive removal can be considered. To meet the requirements for the direct reduction application route, a separation of N2 and H2 is necessary after NH3 removal. In this work, membrane separation was calculated. Using a polyimide membrane, the required H2 purity can be met. To achieve even higher H2 purity, the application of a PSA separation can also be considered.
PSA separation can also serve as subsequent separation step after membrane separation to reach higher H2 purity.
Use case 6: Utilization of CO2 for downstream production
Even in a far future scenario, which considers steel production based on green H2 and Electric Arc Furnaces (EAFs), certain amounts of carbon have to be used for metallurgical reasons. This will lead to unavoidable emission of CO2, however, if captured, this CO2 can be used for the synthesis of urea at LAT. As a result of the conducted estimations considering the current production volumes of VAS, the amount of CO2 will be sufficient to cover “fraction 1” of LAT, which is necessary for the urea production.
Use case 7: Process integration of existing and potential new assets
Since almost all of the analyzed use cases turned out to be rather theoretical with a rather low probability of implementation, except for potential synergies in the area of local production (use case #1) and a potentially coordinated H2 import strategy, the integration of new assets is also still a rather theoretical consideration. In open discussions between the industry partners, with the support of the research partners, the essential technical systems of the use cases were characterized and possibilities were explored. This concerns specific aspects like essential technical assets and their basic specifications, required availabilities, available infrastructure for power/gas/water supply, local available land, approval process, potential ownership structures, financing and funding options, implementation framework and time horizons, basic barriers and opportunities for cooperation.
The level of detail of the technical analysis was determined based on expert opinion and varied widely. Some ideas were evaluated only on the basis of rough estimates, while more promising options were subjected to a detailed examination, e.g., by means of simulation analysis. Due to the nature of the Linz follower case, the overall consideration of the integration of potential new assets (use case 7) remains at a theoretical level between the technical optimization experts of the partners.
The main identified challenges are:
• Currently, the technical options of use case 1 to 7 are at different TRLs, i.e., the verification of technological feasibility is complex. Thus, exchange with potential technology suppliers/ development partners, interface development of streams and processes, process reliability check on production sites, cost analysis depending on technology, scaling and duration of symbiosis implementation needs to be carefully assessed
• Some of the use cases potentially have a low economic and business readiness level, this was addressed in Task 8.2 by cost-benefit analysis and technical studies. However, negotiations and assessments need to be further intensified among the involved parties.
• Also, non-technical barriers related to uncertainties in cooperation, such as contractual obligations, and the legal framework for the switch to renewable production based on green hydrogen as well as CCU and CCS options are still part of the political development processes and discourses on European and national level. Policy makers should closely collaborate with and involve stakeholders from research, industry and civil society to ensure that a supportive legal and funding framework is developed, which adopts a holistic approach.
Technoeconomic estimates to provide Levelized Cost of Energy (LCoE) for the elaborated use cases
In use case 1.3, future hydrogen LCoE of about 8 €ct/kWh_HHV were calculated without consideration of subsidies or similar, which equals about 3.15 €/kg.
In use case 2, the SNG cost range is wider, from 2 to 8.7 €/kg CH4.
None of these scenarios appears to be economically feasible in the short term on the basis of the current initial situation. Operating costs, specifically electricity costs, have the greatest impact on the protential cost structures of on-site renewable hydrogen of synthetic methane production at high full load hours. There is a low competitiveness with high carbon H2 production based, mostly, on average, on grid access costs and electricity taxes that represent nearly 50 % of the cost of hydrogen produced by electrolysis and alone exceed the cost of production with SMR (high carbon H2 production). Then, another interesting point is that, even if there are differences between countries, the electricity OPEX represents more than 80 % of the cost of producing hydrogen from grid-connected electrolysis.
Actually, two kinds of levers to reduce cost production of electrolyzing can be highlighted:
• improving the performance of electrolyzes. Considering that electric OPEXs represent nearly 80% of the price of hydrogen produced by electrolysis connected to the network, lower electricity consumption per kg of hydrogen produced will have a direct impact on the cost per kg of hydrogen.
• In addition, the full load hours of the electrolyzer also have an influence on the H2 production costs. Accordingly, the electrolyzer should be operated with at least 4,000 full load hours to reduce the production costs (here the influence of CAPEX and OPEX decreases significantly). Furthermore, the by-products (excess heat and oxygen) must be used in a profitable way.
• exemption from taxes on electricity: in countries where renewable energy is very competitive (i.e., high wind offshore production), connecting electrolyzes directly to renewable production capacities may be relevant;
Consequently, actually electrolyzing cost is much higher than the cost of hydrogen produced by SMR + CCUS, estimated around € 2.5/kg H2 on average. Currently, low-carbon hydrogen produced from natural gas by SMR or ATR (Auto Thermal Reforming) is assumed to cost in Europe between 1.5 and 2.0 €/kg H2 (Hydrogen Council, 2020), almost in-line with the prevision foreseen from SIA (2020) that presents an average cost of € 2.5/kg H2. In addition, looking only to production cost (see Denmark and German cases of Figure 6.2 – SIA, 2020), the electrolyzing hydrogen is not so far to reach the cost of SMR hydrogen. In 2025, renewable hydrogen will become competitive with low-carbon hydrogen (1.5-2.0 €/kg H2) or with grey hydrogen together with a 50 € per ton CO2 price (Hydrogen Council, 2020). In 2030 renewable hydrogen is expected to become competitive with grey hydrogen, at 1.0-1.5 €/kg H2.
Regarding costs evolution, Hydrogen Council (2020) estimates that with all the improvements expected for the next decade (technology developments, capacity volume, GW scale, low renewable electricity production cost and integrated renewable electricity) the hydrogen production by electrolyzers from renewable sources) will become competitive with low-carbon hydrogen around 2025.
The Hydrogen Council (2020) highlights three main driver for the exploitation of hydrogen for decarbonization.
Need for investments:
• Production = USD 6 billion is required to fund the additional production costs of low carbon hydrogen versus grey hydrogen until 2030 and 70 GW for the electrolyzer capacity;
• Transport = an additional required investment of USD 30 billion for the refueling and distribution networks;
• Heating for buildings and industry = USD 17 billion by 2030 for financing the cost difference between hydrogen and natural gas and investments to build or repurpose the first gas pipeline networks for hydrogen.
Need for policy alignment:
The Hydrogen Council (2020) highlights the importance of both national strategies and coordination between governments and industry stakeholders to mediate potential local investment opportunities, also to pursue standardization. In doing this, through regulation, governments can help remove barriers to invest in the hydrogen economy today, also with the tool of incentives (i.e., tax-breaks). Regarding infrastructure, governments can choose to invest in the deployment of new infrastructure and re-use, where relevant, of existing networks (i.e., natural gas networks).
Need for market creation:
The Hydrogen Council (2020), finally, highlights some interventions to help the hydrogen market to develop itself. These institutional interventions should aim, first, at reducing market uncertainty (i.e., facilitating a shift to end-to-end zero-emission fleet logistics solutions that serve captive, recurring demand). Secondly, focusing on scaling applications and technologies that create the biggest ‘improvement- for-investment’ (see the example of electrolyzers economy of scale). Then, prioritizing the utilization rates in distribution networks, to slow down costs related to distribution. Finally, institutions should invest in low-carbon and renewable hydrogen production.
The analysis of the different technologies available and of the hydrogen market and its projections shows that the context in which companies that are willing to conduct implementations is underdevelopment. Regulatory uncertainties, substantial cost differences between different European countries, an equally important barrier represented from high investments to entry the market, among others, represent strong barriers for those who want to invest in green hydrogen. Among others the hydrogen needs to be produced sustainably, i.e., water electrolysis driven by green electricity. Otherwise, the ecological impact is likely to be even worse than for conventional hydrogen. Thus, the efforts to increase the renewable electricity generation, transport and storage capacities on Austrian and European level need to be intensified, to keep the transition period, when industry and other theoretical developed and characterized use case at Section 5.1.3 will turn into practice the coming years.
In this sense, the Linz consortium already drafted a “vision” for a Linz H2Hub, which will be further intensified in the upcoming project months. So far, the vision document outlines the Austrian hydrogen strategy and summarized the objectives, that should be covered by a Memorandum of Understanding of the companies, which is being envisaged. The draft vision covers aspects such as communication dynamics, BM development, governance structure and monitoring of value generation.