The initial intention for the implementation of power-to-gas plants is, on the one hand, to store intermittent electricity from renewable sources, thus avoiding the shutting down of generation plants in times of power surpluses and, on the other hand, to further integrate power generation in isolated regions. At the same time, systematic research and development of power-to-gas systems has uncovered and developed a wide range of systemic benefits, not only for power generation and transmission but also for energy systems, in general. The systemic approach to the power-to-gas form of energy storage system is the focus of the chapter. For details of electrolysis technologies see also chapter: Hydrogen from Water Electrolysis.

The increased integration of intermittent renewable energy sources such as wind and solar power is an increased challenge to the new flexible model of the energy system. At present, the main centers of research and development of power-to-gas systems are in European countries such as Germany, France, the United Kingdom, and Italy. Smaller investments are to be found in the Netherlands, Switzerland, and Austria and also in Canada and the United States (Fig. 18.2). In recent years, increased integration of renewable energies into the energy system, based on climate policy objectives and targets, has been adopted and implemented at national and multinational levels.

A sustainable and secure energy supply that is economically viable, environmentally sustainable, and socially responsible is a high priority in current energy politics. Due to the fact that the production of fossil fuels is shrinking and the necessity of preventing greenhouse gas emissions, necessary modifications to the energy supply mix have to be made and these changes must also take into account economic considerations.

This political framework based on economic challenges generates positive effects if optimally implemented, but could also cause new problems in the system. A new challenge in recent years is the rising proportion of intermittent electricity production, in particular through increasing production levels from wind and solar sources. Without solution strategies such an intermittent nature of renewable energy causes overcapacity and redundancy and thus increasing destabilization of power grids.

To handle inconsistent energy production from wind and solar sources in a resource-efficient way and thus address a significant challenge to the development of the energy system, the promotion of energy storage is necessary. Currently, there are limited numbers of implemented storage technologies for electrical energy. The only large-volume storage technology which is fully available at the moment (next to more flexible options such as load management) is pumped hydroelectric storage (see chapter: Pumped Hydroelectric Storage). In addition to all the advantages that this technology permits, pumped hydroelectric storage power plants are faced with restrictions such as dependence on topography. Therefore, it is necessary to develop alternative storage technologies and also to take advantage of specific technologies for different system tasks. One option is power-to-gas [3].

Energy storage systems such as power-to-gas will play a key role in integrating renewable energy sources with volatile production sources in addition to optimized power management. The availability of the correct amounts of energy at the proper time period presents a major challenge. Power-to-gas technology could be an important part of future storage portfolios because long-term storage as well as shifts in capacity between energy networks can be realized using power-to-gas, which allows for new possibilities in energy transmission [4].

Power-to-gas technologies and systems are currently (as of 2015) at a nascent stage in their development, with individual pilot and demonstration plants being implemented or designed in different sizes. Power-to-gas technology has specific advantages over other storage technologies. These include the possibility of long-term storage of energy, the ability to store enormous amounts of energy, the displacement of energy transport, and the binding of carbon dioxide. For a detailed explanation of the technological, energetic, economic, systemic, and ecological characteristics, reference is made to the literature, such as Steinmüller et al. [5], Sterner [6], Specht et al. [7], and Müller-Syring et al. [8].

In a nutshell, power-to-gas technology allows for long-term storage of electrical energy which does not already exist in another way within the current energy system, making the energy system more resource-efficient and flexible. This enables accelerated integration and continued realization of low- or zero-emission technologies such as wind power and photovoltaics, thereby promoting the achievement of both climate and energy policy objectives. Furthermore, power-to-gas allows new options in energy transport by load shifting from the power grid to the gas grid. This also reduces socioeconomic challenges such as social opposition to power grid expansions. In addition, power-to-gas technology has many potential strengths such as the incorporation of carbon dioxide in carbon capture and utilization, the provision of a new renewable energy source especially in the mobility market (no competition for acreage with food production), and the possibility of creating self-sufficient primary or backup energy supply systems (including fuel cells) for topographically remote regions or even buildings. The strengths of power-to-gas technology include, in particular, superordinate benefit for the entire energy system and for the economy as a whole [3].

The storage and conversion of energy are always accomplished with broad discussions and analysis about the technical efficiency factor. As expected the conversion of electricity into hydrogen with the option of synthesizing methane comes with reductions in the degrees of efficiency. However, power-to-gas technology is primarily implemented for storing electricity surpluses which cannot be integrated into the electricity system in other ways. Therefore, the introduction of power-to-gas technology into the general energy system can be regarded as an improvement.

Depending on the electrolyte a distinction between alkaline electrolysis cells (AEC), proton exchange membrane electrolysis cells (PEMEC), and solid oxide electrolysis cells (SOEC) has to be made. A more detailed description of the state of the art, latest developments, and characteristics of the different electrolytic types can be found, for example, in Ursua et al. [9] or Smolinka et al. [10] or in chapter: Hydrogen from Water Electrolysis.

Alkaline electrolyzers use an aqueous alkaline electrolyte and provide the most widely used technology with lowest investment costs [11]. AEC systems are considered robust and are already available in high-performance units. Challenges remain, especially in dynamic modes, as efficiency and hydrogen quality are severely affected in partial load operation [10]. Alkaline electrolyzers also require a large amount of space compared with PEM electrolyzers [12]. Further developments of conventional alkaline electrolyzers include improvements related to increased gas pressure. Problems arise, however, when there are leaks in the system as this can cause a discharge of corrosive electrolytes [13].

PEM electrolyzers use a polymer electrolyte membrane and are significantly more compact than alkaline electrolyzers. With better startup performance, faster response to load changes, and higher quality hydrogen (fewer impurities), PEMEC are better suited to dynamic operations. According to Smolinka et al. [10] there are still challenges in terms of the lifespan of the membrane and high-investment costs due to the use of noble metal catalysts such as platinum. In addition, the available power sizes of PEM electrolyzers are still significantly lower than those in alkaline electrolyzers [14].

SOEC electrolysis technology has the greatest need for development. Operation of this electrolyzer is carried out with the use of high thermal energy from an external heat source. The high temperatures result in accelerated reaction kinetics, and hence high-priced noble metal catalysts can be avoided [9]. By using heat the required power is reduced and electrical efficiency is increased. However, challenges exist with regard to material stress due to the high temperatures and, moreover, the SOEC require a large amount of space due to the design of their complex system [12]. The main technical parameters of alkaline and PEM electrolyzers are shown in Table 18.1.

Both alkaline and PEM electrolyzers achieve a system efficiency between (60–70)%. Key challenges for both electrolysis technologies are mainly dealing with fluctuating power input (from renewable energy sources), the present associated lower efficiency, and the hydrogen quality in partial load operations. Highly dynamic operation also has negative effects on the stability of the system. To make power-to-gas technology economically attractive the currently high investment costs for electrolyzers need to be reduced significantly. While PEM electrolyzers respond better to rapid load changes and are well suited to dynamic operations, efficiency and hydrogen quality are severely compromised for alkaline electrolyzers operating at partial load. Although alkaline pressure electrolyzers have improved dynamic behavior, problems arise from leaks in the system and an associated outlet for corrosive electrolytes. Key challenges for both electrolysis technologies lie in dealing with fluctuating power input (from renewable energy sources) and the resulting lower efficiency and life expectancy of electrolyzers (connected to degradation). To make power-to-gas technology economically attractive the currently high investment costs for electrolyzers have to be significantly reduced [3].

The development of new technologies always entails a significant learning curve, which usually leads to a reduction of investment costs with increasing installed capacity or quantity produced. The learning rate is to be determined separately for each technology; a learning rate of 20% has been found to be typical for many components. A learning rate of 20% means a reduction in the specific investment costs of 20% at double the cumulative installed power. For photovoltaic systems, for example, the learning rate is approximately 20%, and for wind turbines the learning rate is estimated to be between (10–15)%. Also learning rates between (15–25)% are estimated for fuel cells [16]. It has been predicted that the future cost development of electrolysis technologies [17] will have a learning rate of 18%. By comparison, the specified learning rate for the production of hydrogen by steam reforming of natural gas (steam methane reforming) is around 11%. When applied to the cost of development of water electrolysis a learning rate of 18% implies that if an increase of 50 times the cumulative installed capacity of PEM and alkaline electrolyzers (compared with current installed capacity) can be achieved by 2025, investment costs of electrolyzers will be reduced by 67%.

In general, there are numerous sources and separation technologies available for the provision of CO₂ for this methanation process, some of which are described in IPCC [18] or Li et al. [19]. A large amount of CO₂ can be obtained from the combustion of fossil fuels or renewable resources in power plants. Postcombustion, precombustion, oxyfuel, or chemical-looping technologies are used for the separation of the CO₂. Depending on the separation technology a certain amount of heat from the power plant is needed, thus increasing the consumption of primary energy. This leads to an overall decrease in efficiency of the power plant by (7–10)%. Furthermore, between (20–40)% more primary energy per generated kilowatt-hour is needed [20,21].

Carbon dioxide can also be obtained from industrial processes such as cement or lime production and from various fermentation processes with purity levels depending on the type of process involved [22]. For the separation of carbon dioxide, various physical and chemical adsorption– and membrane– separation processes can be used (see Ryckebosch et al. [23] for a detailed description). Biogenic sources of carbon dioxide from anaerobic digestion (biogas) or from biomass gasification are possibly the most suitable sources for use in power-to-gas plants [21] (Fig. 18.3).

In theory, CO₂ can also be separated from ambient air but due to the low concentrations in the atmosphere (c. 400 ppm) the energy expenditure necessary for this process is high which leads to high costs. Depending on the separation technology, between (320–440) kJ mol^–1 of CO₂ are needed [24,25].

Once the hydrogen production chain is in full swing and there is a surplus of hydrogen, carbon dioxide need not only be used for methane synthesis, it can also be used for the production of synthetic gas and subsequently liquid hydrocarbons (a process called power-to-liquid). For the conversion of synthetic gas into liquid hydrocarbons there are various methods, ranging from methanol synthesis, Fischer–Tropsch synthesis, oxosynthesis, and fermentation. In addition to the production of synthesis gas as a feedstock for liquid hydrocarbons (power-to-fuel or power-to-liquid), liquid hydrocarbons can also be synthesized directly from CO₂ and hydrogen (or water); for instance, the production of methanol from CO₂ and H₂ as described by Olah [27]. However, these processes and products are not associated with our original definition of power-to-gas and will not be further discussed.

Reverting back to the basic methanation process of the power-to-gas system in which methane (CH₄) is produced from hydrogen and carbon dioxide in a catalytic process called the Sabatier process; see Eq. (18.2). While CO methanation is an already proven technology in coal gasification, CO₂ methanation is still in development. The achievable efficiencies are around 80% (and fast approaching the efficiency of CO methanation), but there are still challenges in terms of thermal management and long-term stability of the catalyst [3].

Typical parameters of CO₂ methanation are shown in Table 18.2. For the methane synthesis different reactor systems are available, which can be divided into two-phase and three-phase systems. In two-phase systems in which fixed, coated honeycomb, and fluidized bed reactors are used, the gaseous reactants and the catalyst are fixed in position. In three-phase systems (e.g., bubble column) a liquid heat transfer medium is used [3].

Generally, five identifiable benefits for the energy system can be stated under our definition of power-to-gas and in turn different solution strategies for different applications can be realized [29]:

The list of basic capabilities implies various forms of process chains, different business models with different technologies, and different benchmarks in the energy system. This makes for compact analysis of current and expected business forms in terms of the compatibility of the system or of competitive technologies. As a consequence, economic evaluation of specific applications of the power-to-gas system and associated competing systems or alternative solutions is necessary.

In the following section a multitude of possible applications of power-to-gas plants are listed. These applications do not include ratings for economic viability, legal implementation, or even a discussion or analysis of optimal operation or the technology involved. The applications are written in such a way that each point has a concrete benefit and specific intention for a market participant for the construction and operation of a power-to-gas plant.

Various applications of a power-to-gas plant for the implementation of a particular benefit to market participants of a specific energy market include the following [4]:

It can be seen then that the power-to-gas process allows for a variety of applications. Of course, the characteristics of a business compatible with the respective benchmarks are also constituted very differently.

As a consequence, power-to-gas can generally be described as a very flexible system in terms of its variety of applications and different forms in national and international energy systems. The different business models that can be developed based on the specific capabilities of the system also imply specific and varied cases for different market players. This expression of a multifunctional use of power-to-gas in the future energy system also has as a consequence a wide economic impact on the technologies involved. The real purpose of the development of the power-to-gas system, however, stems from the challenge of a rising share of intermittent and volatile generation sources and the necessary option for additional energy storage that allows for long-term storage in times of excess production [4].

In addition, it is worth considering the respective advantages and disadvantages of energy carriers, hydrogen, and synthetic methane from power-to-gas plants [4,31]. The advantages of hydrogen over synthetic methane from power-to-gas plants are:

However, there exist several advantages to synthetic methane over hydrogen from power-to-gas plants such as:

Overall assessment in determining unique advantage can only be done on an individual basis case by case. A flexible power-to-gas system allows for the use of both energy sources [31].

The broad range of applications and above all the necessary application of long-term storage of electricity by converting electricity to hydrogen and (with carbon dioxide) to methane via power-to-gas technologies correspond to general forecasts of future long-term substitution within primary energy carriers. Energy-carrying gas and its different characteristics is represented in many forecasts for future power supply as the essential transitional technology or immanent energy carrier on the road to a “hydrogen economy” [4]. Furthermore, the loss of importance of liquid energy sources such as oil and solid fuels like wood, coal, and uranium is predicted by Hefner [32] in the global context. As a consequence the “age of energy gases” is expected to start in this decade as shown by Hefner with respect to future development of the global composition of energy suppliers [32].

Today, underground gas storage facilities are technologically mature and form the backbone of secure energy supplies. Underground gas storage facilities were initially developed to balance out seasonal fluctuations between transport capacities and consumption. Over the past few years, these energy reservoirs have also been increasingly utilized as trading instruments. Chapter: Traditional Bulk Energy Storage—Coal and Underground Natural Gas and Oil Storage provides an overview of underground gas storage technology. According to today’s considerations, underground storage of renewable energy is so attractive because it is the only technology that can be used to store vast quantities of energy over long periods of time and, furthermore, has the unique advantage of being able to balance seasonal fluctuations in energy generation. Fig. 18.5 provides a comparative logarithmic size overview of the storage capacities of various energy storage technologies.

When storing pure methane (synthetic natural gas, SNG), there are no technical problems anticipated in underground gas storage, as methane is the predominant element in natural gas. However, it is necessary to examine particular prevailing national regulatory and legal framework conditions for gas storage, which in many cases have up to now only been defined for natural hydrocarbons. Efforts should be made to amend or supplement these regulations to also include synthetic hydrocarbons. A different story altogether is the storage of pure hydrogen (see chapter: Larger Scale Hydrogen Storage).

Another possibility to be considered is the case where hydrogen is added to natural gas or, due to an incomplete reaction in the methanation process, hydrogen is mixed in with the synthetic methane. The addition of hydrogen into the natural gas infrastructure in controlled amounts is being pursued to achieve greater efficiency in the power-to-gas process and to save investment and running costs involved in the methanation process. Existing infrastructure should continue to be used and, moreover, this path should be pursued wherever there is no existing infrastructure for pure hydrogen.

There have been ongoing efforts in Europe for quite some time to examine the existing natural gas infrastructure in terms of its hydrogen compatibility and to define permissible limit values. On the one hand, gases containing large amounts of hydrogen were in circulation during the city gas era; on the other hand, customer devices available today are unable to handle a certain level of hydrogen content in natural gas. In a first initiative, spearheaded by the NATURALHY project, the pipeline network was examined [35]. In particular, in Germany there were additional studies geared toward examining the whole spectrum of hydrogen compatibility. In these studies it was emphasized that underground gas storage facilities should be examined more carefully for possible reactions with hydrogen [36]. The German Society for Petroleum and Coal Science Technology (DGMK) subsequently commissioned a detailed literature research which resulted in two studies: “Influence of hydrogen on underground gas storage” and “Influence of bio-methane and hydrogen on the microbiology of underground gas storage.” Both studies indicate numerous elements of risk and potential for damage, all of which, however, were derived from related inquiries involving CO₂ research or were based on pure hydrogen applications. Real-life experiments or operating experience based on hydrogen–natural gas mixtures do not exist. It has been pointed out that underground gas storage facilities, due to their varying geology, geochemistry, and operating conditions, should each be viewed individually [37,38] These findings, among many others, were summarized in a European Gas Research Group (GERG) study [39]. An actual project involving an in situ field experiment for underground storage of renewable energy in the form of hydrogen–methane mixtures is currently being carried out in Austria by a consortium led by RAG Rohöl-Aufsuchungs AG under the title “Underground sun storage” [40,41]. A project of a similar nature is being completed in Argentina by HYCHICO. Final results of these projects are expected at the end of 2016.