Design and evaluation of hydrogen electricity reconversion pathways in national energy systems using spatially and temporally resolved energy system optimization

Highlights

• Hydrogen-to-electricity reconversion potential is investigated for Germany 2050.

• Five electricity supply pathways are optimized considering storage and transmission.

• Hydrogen infrastructure complements the electricity grid infrastructure.

• Hydrogen reconversion in combined cycle power plants is most cost effective.

• The pathways can significantly contribute to a secure renewable energy supply.

Abstract

For this study, a spatially and temporally resolved optimization model was used to investigate and economically evaluate pathways for using surplus electricity to cover positive residual loads by means of different technologies to reconvert hydrogen into electricity. The associated technology pathways consist of electrolyzers, salt caverns, hydrogen pipelines, power cables, and various technologies for reconversion into electricity. The investigations were conducted based on an energy scenario for 2050 in which surplus electricity from northern Germany is available to cover the electricity grid load in the federal state of North Rhine-Westphalia (NRW).

A key finding of the pathway analysis is that NRW's electricity demand can be covered entirely by renewable energy sources in this scenario, which involves CO₂ savings of 44.4 million tons of CO₂/a in comparison to the positive residual load being covered from a conventional power plant fleet. The pathway involving CCGT (combined cycle gas turbines) as hydrogen reconversion option was identified as being the most cost effective (total investment: € 43.1 billion, electricity generation costs of reconversion: € 176/MWh).

Large-scale hydrogen storage and reconversion as well as the use of the hydrogen infrastructure built for this purpose can make a meaningful contribution to the expansion of the electricity grid. However, for reasons of efficiency, substituting the electricity grid expansion entirely with hydrogen reconversion systems does not make sense from an economic standpoint. Furthermore, the hydrogen reconversion pathways evaluated, including large-scale storage, significantly contribute to the security of the energy supply and to secured power generation capacities.

Introduction

The climate protection objectives passed by the German Bundestag and the German Federal Government to gradually reduce greenhouse gas emissions by 80–95% by 2050 [1], [2] and to phase out nuclear power by 2022 [3], [4] have led to profound changes in the energy production sector towards an increased share of renewable energy (RE). The steady expansion of solar and wind power, which are largely volatile sources, requires further extensive restructuring of the energy system. At a proportion of 80–95% of fluctuating renewable energy – as expected for the year 2050 – large-scale energy storage will gain importance, as it is required particularly for bridging longer phases of low energy production from renewable sources as well as for easing the strain on the electricity grid during phases of high renewable production. In energy systems using high proportions of renewable energy sources, positive residual loads (electricity deficits) can be covered by means of conventional power plants or large-scale energy storage systems. If electricity deficits result solely from grid bottlenecks, they can be reduced by expanding the grid.

In this context, there is sufficient potential in Germany for storing surplus electricity (negative residual loads) in the form of hydrogen in combination with a demand-oriented reconversion [5]. A schematic of such a hydrogen reconversion pathway is shown in Fig. 1. The reconversion of stored hydrogen offers the opportunity of covering peak loads with renewable gas and thus contributing significantly to achieving the climate objectives. Since the components of hydrogen reconversion systems are characterized by high investment volumes and long investment cycles, it is sensible at this point in time to design and comparatively evaluate pathways which enable the 2050 climate protection objectives to be achieved.

The need for large-scale, but not necessarily high efficient, seasonal electricity storage in energy systems in which close to 100% of the electricity demand is met by wind and solar energy is described by Weitemeyer et al. [6]. Storage systems comprising of hydrogen generation from RE, large-scale hydrogen storage and hydrogen reconversion to electricity can provide such a seasonal electricity storage option. Moreover, the hydrogen reconversion step can be used for combined heat and power generation [7]. In addition, such systems can be a key element in sector-coupling strategies, for example by providing the renewably produced hydrogen to the transport, industry or household sector and thus decarbonizing them [8]. Examples of sector-coupling strategies in the transport and industry sectors are presented by Haghi et al. [9], who in this context highlight the hydrogen storage pathways’ ability to provide seasonal energy storage in energy systems with large shares of wind-based power generation. Nastasi et al. [10] give examples of the incorporation of hydrogen pathways into urbane renewable thermal energy systems. As such, hydrogen storage systems are of high interest for achieving high greenhouse gas emission reductions and are considered e.g. by Luo et al. [11] as one amongst other potential storage options for facilitating the integration of RE into future energy systems. They consider water electrolysis for hydrogen production, high pressure containers for hydrogen storage and a large variety of fuel cell types for hydrogen reconversion to electricity, amongst others alkaline fuel cells (AFCs), polymer electrolyte membrane fuel cells (PEMFCs) and solid oxide fuel cells (SOFCs). Pipelines are named as a hydrogen transmission option. Zakeri et al. [12] conduct a comparative life cycle cost analysis for electrical energy storage systems including various hydrogen storage as well as electrolysis as hydrogen production option. Underground storage is highlighted as cost-beneficial. Fuel cells, hydrogen fired turbines and hydrogen fired engines are listed as reconversion options. Furthermore, Amirante et al. [13] give an overview on recent developments in energy storage and investigate, besides mechanical, electric and electrochemical storage systems also hydrogen storage. They differentiate between different hydrogen production options, such as water electrolysis, steam methane reforming with carbon capture and storage or solar driven hydrogen production, i.e. photo-electrolysis or solar thermal production. Hydrogen storage in compressed or liquified form is classified as traditional storage methods and metal hydrides as an innovative storage option.

As a cost-beneficial storage option, salt caverns are considered in several studies, which investigate hydrogen-based energy storage pathways. Reuβ et al. [14] identify, in a hydrogen supply chain model, hydrogen storage in salt cavern as cost-optimal storage option for high hydrogen demands. Schiebahn et al. [15] investigate a case study for Germany in which hydrogen is stored in salt caverns and supplied to a domestic fuel cell electric vehicle fleet. Le Duigou et al. [16] investigate large scale underground hydrogen storage in France and assess a business case of salt cavern storage facilities for several deployment options of renewably produced hydrogen.

Studies with hydrogen-based energy storage in salt caverns which consider one technology option for hydrogen reconversion are also found in literature. Iordache et al. [17] investigate hydrogen underground storage in Romania and list, besides hydrogen demands for the mobility and industry sector, a hydrogen demand for electricity production in fuel cell plants. Ozarslan [18] studies large-scale hydrogen energy storage in salt caverns in the context of electricity generation from hydrogen enriched natural gas in combined cycle power plants (CCGTs). CCGT for hydrogen reconversion is also considered in a study by Bussar et al. [19] that presents the design of energy storage systems in a future European power system with 100% RE generation. The seasonal storage capability of the hydrogen storage system is highlighted in the concluding remarks of the study. Michalski et al. [20] consider power generation with hydrogen in CCGTs as well. Their study on hydrogen generation by electrolysis and storage in salt caverns in the context of the German energy transition is related to the scenario year 2050. Hydrogen for power generation is considered in the study amongst applications in the mobility and industry sector. For hydrogen production, polymer electrolyte membrane electrolyzers (PEMEL) are identified as economically better-off as alkaline electrolyzers (AEL). Klumpp [21] conducts a comparison of pumped hydro storage, hydrogen storage and compressed air energy storage and in this context also computes levelized cost of electricity/energy (LCOE) of the different systems. He considers a system comprised out of PEMELs, salt caverns and PEMFCs for the hydrogen storage pathway and assumes an electricity purchase for 50 €/MWh. The pathways’ LCOE are computed by a simple formula which relates the cost of the storage systems to their discharged electricity over their lifetime. The study finds that the two largest shares on the LCOE of the hydrogen storage system are the cost for power purchase and the power-specific CAPEX of the system. Jülch [22] compares these electricity storage options as well but additionally considers battery storage and methane storage and reconversion in the context of a methanation pathway. She finds that the hydrogen storage and reconversion (CCGT) pathway exhibits the most economical long-term storage option in a year 2030 context. Electrolysis and reconversion, followed by the cost contribution for electricity purchase (30 €/MWh), have the highest shares on the LCOE. A recent study by Smolinka et al. [23] investigates deployment options of renewably produced hydrogen in the transport, electricity and heat sector in Germany. In a 2050 context, several hundred gigawatts of electrolyzer capacities are installed, which deliver several hundred terawatt hours of hydrogen to the different sectors. Hydrogen gas turbines are used for reconversion to electricity. Hydrogen storage capacities of about 50–150 TW h are identified and the requirement for large-scale underground storage, for example in salt caverns, are emphasized.

Also, several studies which provide a comparative analysis of hydrogen reconversion options in the context of hydrogen-based energy storage are found in literature. Stolzenburg et al. [24] investigate the integration of wind power and hydrogen pathways into the German energy system. They give a very detailed techno-economic overview of the considered hydrogen infrastructure. Wolf [25] lists internal combustion engines, gas turbines and fuel cells as hydrogen reconversion options in the context of large-scale hydrogen energy storage. CCGTs are named as a preferable solution for large scale applications. Steilen and Jörissen [26] focus on hydrogen reconversion into electricity and thermal energy in fuels cells. They give a technology review of several fuel cells, i.e. AFCs, PEMFCs and SOFCs, and list examples of demonstration projects of hydrogen-based electrical energy storage ranging from fuel cell installations in the order of 1 kW–1 MW.

More detailed investigations on the LCOE for different hydrogen reconversion options are given in the following studies. Ferrero et al. [27] conduct a techno-economic assessment of hydrogen as a multi-purpose energy carrier, in which they amongst other applications investigate electricity generation from hydrogen. They investigate combinations of different hydrogen production and reconversion technologies for a 2013 and 2030 scenario. The storage is dimensioned for one week for all combinations and the electricity purchase for the storage system is assumed to be zero. The pathways’ LCOE are computed in a comparable approach to the one of Klumpp [21]. Ludwig et al. [28] conduct exergy and cost analyses of hydrogen-based energy storage pathways. They as well consider different combinations of electrolyzer and fuel cell options but also a CCGT for hydrogen reconversion. Electricity generation and demand time series data underlie the LCOE computation which is based on a year 2050 scenario for a one node Germany with 100% RE electricity generation. An electricity purchase of 10 €/MWh is assumed. The LCOE is broken down into its different contributions and is dominated by the cost for hydrogen reconversion, followed by the cost for hydrogen generation. Hydrogen storage and transmission only play a minor roll. Kotowicz et al. [29] analyze power-to-gas-to-power system for a wide range of electrolyzer and fuel cell efficiency ranges. They provide a methodology with which economically acceptable electricity selling prices can be estimated based on the electricity purchase price. For a round-trip efficiency of 35%, the ratio between selling and purchase price ranges for the considered system setup between 3 (no investment considered) and 9 (investment for electrolyzer and fuel cell with present day cost assumption considered).

Most of the presented studies on hydrogen-based electrical energy storage only analyze hydrogen reconversion options qualitatively or with simple LCOE calculations and consider only one option for hydrogen reconversion. Only some of the presented studies model storage requirements using hourly load time series for one region/node. However, in these studies, since these load time series are not spatially resolved, no conclusions can be made with respect to infrastructure demand or costs. Only the study of Bussar et al. [19] considers a spatial resolution, but it has a strong aggregation on the level of European countries and the only considered transmission infrastructure are HVDC (high-voltage direct-current) lines.

The following study describes an analysis of hydrogen reconversion pathways with spatially and temporally resolved load data, in which energy transfer using the necessary infrastructure (hydrogen pipelines and underground HVDC² cables) is integrated in the model, thus allowing a subsequent economic evaluation to be conducted. The aim of the system design is to cover the positive residual load at every point in time and in every region of the German federal state of North Rhine-Westphalia (NRW) in the scenario year 2050 by means of surplus electricity from northern Germany. The industrial state of NRW was selected because the majority of its electricity demand is currently covered by coal-fired power plants, which will gradually have to be taken offline within the coming two decades in order to achieve the climate protection goals. In addition, this most densely populated German state has comparatively little potential for the expansion of renewable energy.