An innovative approach that complies with essential demands of the European Strategic Energy Technology Plan (SET Plan) is the patented PGP technology, an extension of the conventional P2G concept. This “system and method for ecologically generating and storing electricity” (Kühn, 2013) considers the conversion of excess renewable energy to hydrogen, and subsequently to methane by using carbon dioxide that is maintained in a closed cycle (Fig. 1).

If the current electricity demand is lower than its production from renewable sources, excess electricity from, e.g., wind power (i), is transformed into H2 (ii) and then into CH4 using CO2 (iii). CH4 is stored in a reservoir in the geological subsurface (iv) and electrified on demand (v) in a Combined-Cycle Gas Turbine power plant (CCGT). CO2 is captured from the CCGT power plant's flue gas and stored in a secondary subsurface reservoir (vi), closing the carbon cycle. The added value of a closed carbon cycle by capturing and temporarily storing CO2 in a subsurface reservoir results from CO2 being always at hand when excess energy needs to be transformed into CH4 (Fig. 1).

Energy storage on the basis of methane offers three major advantages over hydrogen storage: (i) it represents the current state-of-the-art and can be applied immediately, (ii) retransformation of methane into electricity can make use of established power plant technologies, and (iii) methane can be easily fed into the existing natural gas network. This is why an essential contribution to the electricity market in Germany and in Europe can be expected (Kühn et al., 2014a).

CCGT power plants are advantageous, because they can be flexibly started up and shut down for load balancing and base load provision in the electricity network. Furthermore, the power output is scalable over a range between 80 and 400 MW per block, what makes the system profitable even for smaller units. Hence, decentralisation and control of electricity in “smart grids” is supported (Streibel et al., 2013; Sterner and Stadler, 2017).

The overall efficiency of the PGP approach is given by Streibel et al. (2013) based on chemical energies taking into account reaction enthalpies for all process steps included. Therein, methanization is presumed with an efficiency of 80 % and electrolysis as well with 80 % (DVGW, 2014). CCGT is based on a 60 % efficiency (Nakaten et al., 2014), reduced by the energy loss of 8 % due to coupled CO2 capture with an efficiency of 90 % (Metz et al., 2005). The result is a total efficiency of the entire PGP process of 26 %. This is without the provision of residual heat, which would further increase the efficiency. It is important to note that subsurface storage is literally insignificant for the overall efficiency causing a loss of only 0.2 % (Streibel et al., 2013).

In addition, it is shown that one subsurface storage reservoir for both gases, CH4 and CO2, in combination with the proven Enhanced Gas Recovery (EGR) operation provides an alternative option for the outlined concept (Kühn et al., 2014b). EGR helps to maintain and manage the reservoir pressure, increase the sweep efficiency and production rates (Metz et al., 2005). In fact, EGR works in both directions. On the one hand, CO2 injection enhances CH4 recovery, and on the other hand CH4 injection displaces CO2 equally efficient (van der Meer, 2005). The ideal depth for EGR is expected to start at 700 m, where CO2 density and viscosity start to notably increase depending on temperature and pressure. The biggest jump in density occurs between 70 and 90 bar. The increase of both values for CH4 is gradual and substantially lower within this range. The larger the difference in density and viscosity of both gases, the lower the occurring gas component mixing. However, mixing of both gases in the reservoir is inevitable and needs to be minimised to optimise the efficiency of single-reservoir P2G systems. Feasible injection rates and injection schedules can be derived from an integrated reservoir stability analysis (Ma et al., 2019).

The State Office for Mining, Energy and Geology of Lower Saxony (LBEG, Hannover) annually compiles relevant data from industry. The statistical and descriptive information about the natural gas storage serves companies and politics as a source of evidence and information. More than 40 subsurface storage sites for natural gas exist in Germany to date (EID, 2019). They provide a total storage capacity of around 24 billion sm3 (= standard cubic metres) of CH4 working gas, which represents an energy equivalent of around 240 TWh (specific calorific value of approximately 9.8 to 11.5 kWh m-3 depending on the average gas quality). These sites are either porous formations (16 in operation, 38 % of total working gas volume) or caverns in salt structures (31 in operation, 62 % of total working gas volume). As caverns are assumed to be almost completely gas-tight, they should probably be preferred for H2 storage in the near future. Therefore, our estimate is solely based on the existing and operating 16 storage sites in porous media (Table 1). The working gas volume of these sites is around 9 billion standard m3 with an energy equivalent of 90 TWh. The total gas volume stored in porous media is around 18 billion standard m3, representing an average ratio of 50 % working gas to 50 % cushion gas. The depth of the 16 storage sites ranges from 350 m down to 2930 m and the reservoirs used are either saline aquifers or former oil and natural gas deposits. Reservoirs in former gas deposits are of pronounced importance for the German storage capacity in porous media (Table 1). The advantage of former deposits is the excellent data basis for the description of the reservoirs and their caprocks, and thus the deduction of potential overall storage performances. The respective sandstone formations are located in the sedimentary basins of North, East and Southern Germany (EID, 2019).

Our previous economic assessments have shown that PGP is economically competitive compared to conventional storage technologies, whereby its efficiency still requires optimization (Streibel et al., 2013; Kühn et al., 2014a, b). Hereby, energy production and storage technology economics used in the previous assessment originate from the year 2012. However, cost trends related to energy production and storage significantly correlate with fuel and commodity prices. For example, CO2 emission charges as well as technology improvements rapidly changed in the past few years. Therefore, we update the classification of the PGP competitiveness within the presented study.

The answer to the question how much storage capacity is already available in the German geological subsurface is based on the sites in operation (EID, 2019; Table 1). In view of an EGR process, it is outlined that the preferable depth for the mutual displacement of CH4 and CO2 is 700 m and below (Kühn et al., 2014b). This reduces the number of suitable storage sites (Table 1) to 10 of 16 with a total working gas volume of around 8.7 billion standard m3, representing an energy equivalent of more than 80 TWh. Following this criterion, the suitable German sites are Bad Lauchstädt, Bierwang, Breitbrunn-Eggstätt, Frankenthal, Fronhofen-Illmensee, Inzenham, Rehden, Schmidhausen, Uelsen and Wolfersberg (Table 1), whereas the reservoirs of Allmenhausen, Eschenfelden, Hähnlein, Sandhausen and Stockstadt are too shallow. Except for the site Frankenthal, representing a saline aquifer and Fronhofen-Illmensee, located in a former oil deposit, the other seven candidate sites use reservoirs in former gas deposits.

Feed-in management refers to regulations that are applied to renewable energy systems, so that electricity produced cannot be fed into the power grid. Restrictions are necessary if parts of the power grid are overloaded. The majority of the regulated amount of electricity comes from wind energy. In 2017 and 2018, over 5 TWh of wind energy had to be curtailed (Renewable Energies Agency, 2020). However, instead of regulating systems, it would make more sense to store the electricity. The described technology provides in that way much more than the capacity needed at the moment. Sterner and Stadler (2017) compare ten different scenarios for the energy market of Germany and estimate an average of just below 80 TWh excess energy and required storage capacity for the year 2050. The presented numbers show that this demand can be covered by geological storage.

The answer to the question how competitive the technology is, was derived based on cost data applied to ascertain current and future market trends from different literature sources. Cost of electricity (COE) bandwidths for photovoltaic (4 to 22 eurocents per kWh), solar thermal power (4 to 23 eurocents per kWh), wind offshore (7 to 14 eurocents per kWh) and onshore (5 to 9 eurocents per kWh) as well as fossil fuels (4 to 10 eurocents per kWh), consisting of upper and lower limit COE for lignite, hard coal and gas fired power plants, were taken from Höfling (2016) and the Global Renewable Energy Status Report (REN21, 2017). Hereby, newly installed RE plant costs vary widely, depending on site quality, specific economic characteristics and direct normal irradiance (DNI) levels of a given location. Thereby, cost differences in the conventional energy production technologies arise rather from varying operating hours (REN21, 2017). Considerable cost uncertainties with respect to conventional energy production technologies are future fuel and CO2 emission fee developments. Variations in pumped storage hydropower costs are also related to site-specific conditions such as catchment geology and hydrogeology, access to transmission grids as well as overall construction costs. According to the Global Renewable Energy Status Report (REN21, 2017) and the National Hydropower Association's Pumped Storage Development Council (PSDC, 2017), the bandwidth of pumped storage costs covers a range of 43 to 149 eurocents per kWh. A cost position of high uncertainty is the charge for transmission interconnection, which was not considered in the suggested cost bandwidth. These costs can range from negligible charges to substantial amounts according to existing transmission line capacities as well as size and distance of new lines (IRENA, 2017). Since pumped hydropower storage is a technology with decades of operating experience, major technology improvements are not anticipated in the future in terms of costs, structures and transformation efficiency (IRENA, 2017). The COE bandwidth for compressed air energy storage systems were derived to be 30 to 55 eurocents per kWh. However, an increased utilization of waste heat from compression is expected to improve average efficiencies by 2030, resulting in further cost reduction (IRENA, 2017). According to the Handbook of Energy Storage for Transmission or Distribution Applications (EPRI, 2002), levelized costs of pumped hydropower storage and compressed air energy storage represent the lowest cost forms of large grid-scale energy storage technologies.

Taking into account costs for energy conversion during the hydrogenation and methanation processes as well as all costs related to CO2 capture and gas storage operation, study case-related PGP costs can currently not compete with the aforementioned global fossil and onshore/offshore wind energy production technology COE, which are exceeded by 30 % to 80 % (Fig. 2). However, PGP costs are up to 10 % below those of upper limit solar thermal power and photovoltaic COE as well as up to 80 % below pumped hydropower and compressed air energy storage costs, and thus competitive on the global energy market (Fig. 2).