• Energy Research

Abstract Rare earth permanent magnets are important components for modern (energy) technologies and are employed to reduce GHG emissions and combat climate change. The process of extracting these minerals from the ore has contentious economic, environmental and social implications. While the environmental impacts of their production have already been analyzed in several studies, the economic and the social perspective is still under-researched. The Social Life Cycle Assessment (S-LCA) approach employed in the present research explores whether there is a difference in social risks for rare earth permanent magnet production from three different rare earth ore production locations and the associated value chains. While one is located completely in China, another is composed of processes in Australia and Malaysia. The third process chain combines processes in the United States and Japan. The Product Social Impact Life Cycle Assessment (PSILCA) 2.0 database is used to assess the social implications. The analysis focuses on value chain actors, a stakeholder group of great interest to businesses but often underrepresented in S-LCA research. The impact categories describing this stakeholder group pertain to issues of social responsibility along the value chain, fair competition and corruption. Overall, the US value chain indicates the lowest level of social risk along the supply chain. However, in order to gain a deeper understanding of the social risks a sectoral and geographical analysis is conducted. Across all three cases, the mineral, fossil fuel and chemical sectors are shown to be problematic.

Industrial hydrogen production via alkaline water electrolysis (AEL) is a mature hydrogen production method. One argument in favor of AEL when supplied with renewable energy is its environmental superiority against conventional fossil-based hydrogen production. However, today electricity from the national grid is widely utilized for industrial applications of AEL. Also, the ban on asbestos membranes led to a change in performance patterns, making a detailed assessment necessary. This study presents a comparative Life Cycle Assessment (LCA) using the GaBi software (version 6.115, thinkstep, Leinfelden-Echterdingen, Germany), revealing inventory data and environmental impacts for industrial hydrogen production by latest AELs (6 MW, Zirfon membranes) in three different countries (Austria, Germany and Spain) with corresponding grid mixes. The results confirm the dependence of most environmental effects from the operation phase and specifically the site-dependent electricity mix. Construction of system components and the replacement of cell stacks make a minor contribution. At present, considering the three countries, AEL can be operated in the most environmentally friendly fashion in Austria. Concerning the construction of AEL plants the materials nickel and polytetrafluoroethylene in particular, used for cell manufacturing, revealed significant contributions to the environmental burden.

Abstract Microgrids integrating local renewable energy sources at low-voltage level show promising potentials in realizing a reliable, efficient, and clean supply of electricity. Further improvements are expected when such a microgrid is operated based on direct current (dc) instead of alternating current (ac) infrastructure for power distribution commonly in use today. Our study aims to systemically quantify the gap between environmental impacts of microgrids at building level using the case study of power distribution within office buildings. For this purpose, a scalable comparative life cycle assessment (LCA) is conducted based on a technical bottom-up analysis of differences between ac and dc microgrids. Particularly, our approach combines the micro-level assessment of required power electronic components with the macro-level requirements for daily operation derived from a generic grid model. The results indicate that the environmental impacts of employed power electronics are substantially reduced by operating a microgrid based on dc power distribution infrastructure. Our sensitivity analyses show that efficient dc microgrids particularly lead to savings in climate change impact emissions. In addition, our study shows that the state-of-the-art scaling rules of power electronics currently used in LCAs leads to inaccurate results. In contrast, the proposed methodology applies a more technical approach, which enables a detailed analysis of the environmental impacts of power electronic components at system level. Thus, it provides the foundation for an evaluation criterion for a comprehensive assessment of technological changes within the framework of energy policy objectives.

Abstract The controversial and highly emotional discussion about biofuels in recent years has shown that greenhouse gas2 (GHG) emissions can only be evaluated in an acceptable way by carrying out a full life cycle assessment (LCA) taking the overall life cycle including all necessary pre-chains into consideration. Against this background, the goal of this paper is it to analyse the overall life cycle of a hydrogen production and provision. A state of the art hydrogen refuelling station in Hamburg/Germany opened in February 2012 is therefore taken into consideration. Here at least 50% hydrogen from renewable sources of energy is produced on-site by water electrolysis based on surplus electricity from wind (mainly offshore wind parks) and water. The remaining other 50% of hydrogen to be sold by this station mainly to hydrogen-fuelled buses is provided by trucks from a large-scale production plant where hydrogen is produced from methane or glycerol as a by-product of the biodiesel production. These two pathways are compared within the following explanations with hydrogen production from biomass and from coal. The results show that – with the goal of reducing GHG emissions on a life cycle perspective – hydrogen production based on a water electrolysis fed by electricity from the German electricity mix should be avoided. Steam methane reforming is more promising in terms of GHG reduction but it is still based on a finite fossil fuel. For a climatic sound provision of hydrogen as a fuel electricity from renewable sources of energy like wind or biomass should be used.

The gasification of biomass and the subsequent conversion to electric power, heat, or synthetic natural gas (SNG) offers the possibility to produce different products in one process under minimizing potential losses. In a so called polygeneration approach, the operation of such a process may be linked to changing energy market situations to improve the economic viability. The integration of water electrolysis for hydrogen production enables the process to provide positive as well as negative controlling power; i.e. it can provide system service and contribute to the stability to the electricity grid. Against this background, the aim of this paper is the technical, economic and environmental analysis of a polygeneration approach based on biomass gasification processes for the provision of SNG, heat and power taking the current electricity spot market into consideration. Therefore, several processes schemes are developed and analysed in terms of process efficiency (exergetic efficiency), economic viability (SNG production costs) as well as environmental performance (specific greenhouse gas emissions). For comparison, a biogas-based polygeneration approach for the production of biomethane, heat and power is analysed as well. In case of an operating mode optimised for SNG production, the exergetic efficiency results between 65.4 and 67.2 % for the gasification-based processes and 55.6 to 63.3 % for the biogas-based processes. If primarily electric power is provided in case of high spot market prices, the operation mode is optimised for power production; this results in significantly lower exergetic efficiencies of 48.0 to 44.9 % for the gasification-based processes and 38.0 to 41.2 % for the biogas-based processes. The production costs are calculated depending on the full load operating hours for maximizing SNG production and maximised power production, respectively. The results show a clear dependency of SNG production costs from the operating hours for all processes. The GHG emissions for maximum SNG production range between 43.4 and 95.1 gCO2-eq/kWhMethane. If more power is produced, the emissions rise to values between 55.4 and 127.6 gCO2-eq/kWhMethane. Lower emissions can be achieved by SNG production via gasification than via biogas.

Abstract Renewably produced hydrogen offers a solution for mobility via fuel cell electric vehicles without emissions during driving. However, the hydrogen supply chain, from hydrogen production to the fueling station – incorporating seasonal storage and transport – varies in economic and environmental aspects depending on the technology used, as well as individual conditions, such as the distance between production and demand. Previous studies have focused on the economic aspects of varying technologies and elaborated application areas of each technology, while environmental issues were not specifically considered. To address this shortcoming, this paper presents a life cycle assessment of three supply chain architectures: (a) Liquid Organic Hydrogen Carriers (LOHCs hereinafter) for transport and storage; as well as (b) compressed hydrogen storage in salt caverns, together with pipelines; and (c) pressurized gas truck transport. The results of this study show that the pipeline solution has the least environmental impact with respect to most of the impact categories for all analyzed cases. Only for short distances, i.e., 100 km, is truck transport better in a few impact categories. When considering truck transport scenarios, LOHCs have higher environmental impacts than pressurized gas in seven out of 14 impact categories. Nevertheless, for longer distances, the difference is decreasing. The seasonal storage of hydrogen has almost no environmental influence, independent of the impact category, transport distance or hydrogen demand. In particular, strong scaling effects underlie the good performance of pipeline networks.

Abstract This study develops a method to identify the minimum cost of establishing hydrogen infrastructure using a mono-objective linear optimization. It focuses on minimizing both the capital and operation costs of hydrogen transportation. This includes costs associated with the establishment of storage and compression facilities as well as transportation links. The overarching goal of the study is therefore to build a cost-efficient transportation network using compressed gas trucks for mobility and to apply it to the federal state of North Rhine-Westphalia by 2050. It is assumed that hydrogen production will be established by 2050 and, based on excess electricity from wind energy in North Rhine-Westphalia and the surrounding areas, limited by the projected installed wind installed capacity by 2050. Hydrogen is then distributed as a compressed gas, depending on the hydrogen demand of a given year, for each NUTS 3 district of North Rhine-Westphalia in 2030 and 2050. The results show that the hydrogen demand on the region, which increases from 2030 to 2050, has an impact on how and at which flow hydrogen demand is transported from the production nodes to the different distribution hubs. In 2050, hydrogen is predominantly transported and stored between the storage nodes and the distribution hubs at a high-pressure level of 500 and 540 bar, whilst it is mainly transported at 250 and 350 bar in 2030. Production is predominantly found to be transported at high pressure for both years and located in the region in 2030, whereas imports from the south and north are required in 2050.

How to combine multi-criteria decision analysis into sustainability assessment with the integration of stakeholders for weighting factor determination, and how to assess hydrogen mobility.

Abstract One option to transport hydrogen over longer distances in the future is via Liquid Organic Hydrogen Carriers (LOHC). They can store 6.2 wt% hydrogen by hydrogenation. The most promising LOHCs are toluene and dibenzyltoluene. However, for the dehydrogenation of the LOHCs – to release the hydrogen again – temperatures above 300 °C are needed, leading to a high energy demand. Therefore, a Life Cycle Assessment (LCA) and Life Cycle Costing are conducted. Both assessments concentrate on the whole life cycle rather than just direct emissions and investments. In total five different systems are analysed with the major comparison between conventional transport of hydrogen in a liquefied state of matter and LOHCs. Variations include electricity supply for liquefaction, heat supply for dehydrogenation and the actual LOHC compound. The results show that from an economic point of view transport via LOHCs is favourable while from an environmental point of view transport of liquid hydrogen is favourable.