Prof. Dr.-Ing. Martin Dehli, Hochschule Esslingen January 2014
Contribution to the Facts about Energy
Power to Gas:
Storage of electricity from wind power plants and photovoltaic
power plants in the natural gas infrastructure
Summary
In order to increase the share of renewable energy sources; i.e., wind power plants and solar energy in electricity
generation, a comprehensive expansion of storage capacity for electrical energy will be needed. Suitable
technology primarily includes pumped storage hydro power stations, compressed air storage units, and chemical
energy sources. Chemical energy sources - hydrogen and methane - in combination with the existing natural gas
infrastructure - might open up interesting storage options.
In order to be able to use the well-developed natural gas infrastructure for transport and storage, hydrogen (H2)
may be produced from excess electricity by using electrolysers and possibly - in addition - the obtained hydrogen
may be converted to methane (CH4) by using methanation units (power-to-gas concept). These gases might then,
at a different time and in a different place, either be re-transformed into electricity, used for heat supply, or utilised
in the transport sector.
Recent investigations performed by the German Association for gas and water applications (Deutscher Verein des
Gas- and Wasserfaches , DVGW) assume that an average of up to 10% hydrogen may be added to the natural
gas to be fed into the natural gas grid. The H2 compatibility of structural elements in the natural gas grid and in gas
consuming technologies is usually guaranteed. The CH4 compatibility of the natural gas infrastructure is no
problem, anyway. The specific costs of power to gas concepts depend considerably on the pertinent site
conditions. Given the cost structures at this point in time, this is not profitable, not even at optimum site conditions;
although profitability may quite possibly be achieved in the long term.
1. Fluctuating electricity generation from sunlight and wind will lead to high adaptation and storage
capacity requirements
The Federal Republic of Germany has set itself very ambitious goals in line with the aspects of climate protection,
energy efficiency, and increased use of renewable energy sources. In conjunction with the envisaged energy
turnaround, the Federal Government in office up until the autumn of 2013 specified, among others, that CO2
emissions – in relation to the base value of 1990 - were to be reduced by 40% till 2020 and by 80% till 2050.
Besides, by 2020, 35% of the total electricity requirements are to be met by renewable energy sources; by 2050,
the renewable energy contribution is to be 80% [1 - 4]. In view of the numerous long-term efforts needed to
achieve this and the additional costs involved as opposed to the foreseeable price stability for fossil energy
sources - natural gas, hard coal, and brown coal [5 - 8] (see Figure 1 [5]), accompanied by a considerable
electricity price increase [8] and a rather reserved stance of other countries toward certain aspects of the German
energy turnaround, it remains to be seen in how far the new Federal Government formed in late 2013 will
perpetuate the pertinent goals specified by the previous government.
Figure 1: Price trend of imported energy
sources between 2008 and 2013 [5]
[imported crude oil
imported natural gas
coal from third countries]
In 2013 in Germany, 23.4
% of the electrical energy was generated from
renewable energy sources who contributed a
total of 147,3 billion kWh. Major contributing
factors were
biomasses as well as wind and solar
energy: electricity from wind power equalled
49.8 billion kWh (7.9
%), electricity from photovoltaic units
equalled 28.3 billion kWh (4,5%), and electricity
from solid, liquid, and gaseous biomasses was
48.0 billion kWh (7.6%) [5]. Wind and solar
power are expected to have significant potential
for future development: In 2020, according to
[4], electricity from wind and solar power is
expected to reach a total of 103 billion kWh
(53.5 billion kWh from land-based wind
power stations, 33.7 billion kWh from sea-based wind power plants, and 15,5 billion kWh from photovoltaic power
plants) [4]. As early as 2014, the generated quantity of photovoltaic power will be at least twice as high as the
value expected for 2020, according to [4].
Power generation from wind and solar energy is not normally needs-based and also varies considerably with time;
besides, it shows considerable quantitative fluctuations: The range of variation may be observed in the course of
several months (seasonally) as well as locally within a few hours to seconds (for instance due to shading caused
by clouds, local weather conditions, or sudden spells of calm weather). Thus, the contribution of wind-sourced
electricity to the base load power supply in Germany is only about 8 to 15% of the total quantity of wind-generated
electricity [9]; similar values are found for photovoltaic power supply.
The electricity grid has no storage capacity in itself; this is why the quantities of power generated need to match
power consumption at any given time. This means that any variations with regard to electricity generation and
power consumption have to be compensated immediately by flexibly supplying or removing large quantities of
electrical energy via power plants, reservoirs, and control systems.
In the meantime, studies were performed assessing the required storage capacities that will be needed to
compensate a fluctuating power output from wind power and photovoltaic plants. To this end, complex models
were developed based on a variety of different scenarios regarding the contributions of renewable energy sources,
various assumptions regarding demand for electricity, developments in the heating market and the transport
sector, various possibilities of load management, and on statistical data – such as weather data
. [10 - 13].
One of these studies shows that, even if renewable energy sources contribute less than 50% of the total power
supply, power peaks may occur in the German electricity grid that are unable to meet the actual demand [10].
Another study ([13] performed by the Umweltbundesamt (Szenario „Regionenverbund“) predicts a surplus power
of up to about 60,000 MW in excess of the required power for 2050, as well as a temporarily postponed power
deficit of up to about 60,000 MW between the required power and the currently available power from renewable
energy sources. This is on the assumption that renewable energy sources will provide 100% of the total electricity
generated. In view of the electricity demand forecast and the considerably fluctuating electricity generation, the
grid requires high storage capacities; otherwise, surplus power as well as power deficits would create considerable
problems (Figure 2). In 2012 and 2013, electricity was sometimes sold far below cost price, for instance to foreign
grids, occasionally giving rise to negative electricity prices [9].
[Fig. 7-19 Use of electrolysis, hydrogen re-conversion, biogas re-conversion, and imports in 2050 for the meteorological years 2006-2009
Electricity imports and use of electrolysis and re-conversion (meteorological years 2006-2009)
Power output (GW)
Maximum residual load: 57.3 GW
Electrolytic output: 44 GW
Year
Biogas reserves, Re-conversion to electricity, Import, Biogas cogeneration (combined heat and power), Electrolysis, Throttled-down surplus]
Figure 2: Residual load at 100% power supply from renewable energy sources in 2050: Deficits with regard to
load coverage (above); excess electricity generation (below); requirements of storage concepts based on powerto-gas principles (hydrogen generation from excess electricity by electrolysis as well as possibly methanation and
re-conversion to electricity using GuD (combined cycle) power plants) [13]
The scenario described by the Umweltbundesamt [13], for instance, may lead to the conclusion that at a temporary
maximum residual load of almost 60.000 MW - assuming a two- to three-week transition period caused, for
instance, by windless days - the storage capacity requirements are about 17 billion kWh or 25 billion kWh,
respectively [14]. The existing infrastructure in Germany is far short of the mechanical / electrochemical storage
capacities required to provide the required electricity storage.
One option regarding storage of excess electricity from renewable energy sources and its quick supply in
accordance with the demand is based on producing gaseous fuels, making use of the existing natural gas
infrastructure in Germany. At this point in time, the gas supply companies in Germany have underground natural
gas storage caverns (pore and cavern storage) offering natural gas storage facilities of almost 25 billion standard
cubic meters (Nm³) [15]; which corresponds to a storage capacity of approximately 230 billion kWh. Storage
facilities under construction as well as projects to be completed in the foreseeable future will extend this storage
space to more than 36 billion Nm³ (which equals about
400 billion kWh) [16]. In accordance with [14], this capacity exceeds the assumed demand for
balancing the fluctuating supply of electricity from wind and solar energy plants many times over.
In 2013, annual natural gas consumption in Germany was about 89.6 billion Nm³ (875 billion kWh [5]). Thus, the
ratio between the storage capacity and the annual natural gas consumption is about
23%; which corresponds to a time period of approximately 80 to 90 days per year where the average
consumption may be supplied by the storage facilities. Assuming reduced
„fossil“ natural gas consumption in accordance with [12] in the future, additional storage capacities would
become available.
2. Storage technologies
The following technologies allow direct and indirect storage of electrical energy
(see also [17, 18):
In today's electricity industry structure, pumped storage hydro power stations as well as storage power stations are
most relevant for the provision of balancing energy. In pumped storage power plants, water is being pumped from
of lower reservoirs to higher ones, converting electrical energy to potential energy. As soon as electricity demands
increase once more, the water passes through turbines to reach lower reservoirs. Modern power stations achieve
an electrical efficiency of up to 85% [19]; a performance that surpasses other storage options. Enhancing the
capacities of pumped storage hydro power stations in Germany (which would be the most cost-effective energy
storage option) is politically difficult to implement [18]. The storage capacity is about 2.3% of the average daily
electricity demand in Germany today; which is insufficient to meet future power requirements. [21]. The
construction and use of pump storage hydro power stations being built, for instance, in Norway to meet German
power supply, are limited by the lack of maximum voltage connections.
Compressed air storage power stations: Germany has experience with compressed air storage in a power plant in
North-Western Germany. In this case, power is used for high-pressure air compression; with increasing electricity
demand, the stored energy is re-converted into electricity by unloading via turbines. The low energy storage
density necessitates large-sized compressed air storage units - for instance in large subterranean caverns. In
order to obtain efficiencies of 50 to 60%, the heat released during compression must be extracted from the air,
stored as well, and returned during air expansion [19]. Such procedures will be technically feasible in the future
and may reduce the specific costs of compressed-air storage, which today is significantly above those of pumped
storage hydro power stations.
Flywheels, electrochemical capacitors and superconducting coils are able to briefly - for a few seconds – absorb
and release considerable amounts of energy. The efficiency, however, decreases considerably with the storage
duration (for instance during a period of several hours) up to complete discharge. This is why such storage
facilities do not lend themselves to long-term storage. Owing to their high specific costs, these technical solutions
are economically unsuitable for use in the electricity industry.
Electrochemical storage units convert reactants (reagents) into products with a higher chemical energy content by
an endothermic electrochemical reaction, for instance by supplying electricity. If needed, power may be generated
by a corresponding reverse reaction. In electrochemical storage facilities with internal storage units, the reaction
chamber and the energy storage location are identical (for instance in lead-acid accumulators and lithium-ion
batteries). Currently, high specific costs, a low energy density, and gradual self-discharge and degradation are
considered disadvantageous. In electrochemical storage facilities with external storage units (such as hydrogen
pressure reservoirs), the products are stored separately. This allows large-sized storage facilities and long storage
periods [14].
In order to expand the existing capacities for storage and buffering of electricity for the foreseeably increasing use
of regenerative energies, efforts should be made to find feasible solutions. It appears that chemical energy sources
are technically interesting to achieve high volumetric energy densities during storage.
Hydrogen (H2) gas seems to be particularly suitable for this purpose, since it may be produced by electrolysis of
water with excess electricity, stored, and re-converted to electricity whenever needed. However, in Germany apart from an H2 interconnection system in the mining district in the Rhineland - there is no nationwide
infrastructure for the transport, distribution, storage, and the use of hydrogen. The gas industry, on the other hand,
has extensive experience with this gas. After all, with a share of more than 50%, it is the primary component of the
town gas that was used as an energy source up until the 1970s and is still contained to a similar degree in coke
oven gas. In the future, it may be possible (within reasonable limits) to add hydrogen to natural gas. Current
research shows that mixing ratios that are at least in the single-digit percentage range may be achieved without
any technical problems [22, 14]. This is discussed in more detail below.
Apart from hydrogen, methane (CH4) also seems to be an interesting energy storage device. The volumetric
energy density of methane is about three times as high as that of hydrogen [23] and more than 26 times as high as
that of compressed air at the same pressure. Primary arguments in favour of methane as a chemical energy
storage device include its versatility; i.e., its suitability for most energy applications and its ease of handling: All
existing heating appliances, natural gas-powered vehicles, and other natural gas applications may easily be
operated with synthetic methane (SNG). Large volumes of SNG would lend themselves to heating market
purposes. Besides, SNG appears to pose no technical problems regarding re-conversion to electricity - for
instance to generate peak-load electricity and power for control tasks.
The initiative of a Southern German automotive manufacturer (see Figure 3) [25] may serve as an example of the
production of hydrogen from wind power, its conversion into methane, and the use of methane in natural gaspowered vehicles.
[Wind energy
The Audi e-gas project is based on regenerative power generation.
Electricity grid
Wind power is being fed into the public electricity grid.
Gas grid
The e-gas is stored in the public gas grid and can thus supply energy from renewable sources to domestic as well as industrial customers.
Electrolysis
The wind power – driven electrolysis unit splits water into oxygen and hydrogen.
Methanation
In a methanation plant, hydrogen reacts with carbon dioxide, yielding e-gas (synthetic natural gas)
CNG filling station
Increasing e-gas contributions enhance environmentally friendly long-distance mobility.]
Figure 3: Diagram of the power plant in Werlte for the production of methane from wind
power (e-gas generating facility at Audi AG) [25]
3. Storage of hydrogen or methane, respectively, from wind and solar power in the natural gas
infrastructure
From the perspective of the gas industry, chemical energy storage devices seem to be a reasonable approach to
balance supply with demand in view of the fluctuating electricity generation. This was confirmed by numerous
expert opinions and studies (for instance by [22]. In conjunction with the possible configuration of an
interconnection of H2 and possibly also CH4 production plants, storage facilities, and grid connections, the
following strategy appears to be preferable: An electrolyser is used to produce hydrogen from excess electricity.
This is then fed into the natural gas grid and also - to the extent necessary - used to produce methane (SNG) as a
chemical energy storage device. Apart from hydrogen, a mixture of hydrogen and SNG may possibly be fed into
the natural gas grid. Potential markets include the existing natural gas grid; i.e., power plants, thermal power
stations or decentralised combined heat and power plants, the building heating market, the commercial and
industrial heating market, as well as the transport sector (Figure 3) [14].
Various DVGW (German Technical and Scientific Association for Gas and Water) research projects have
investigated the maximum hydrogen admixing ratio with regard to the gas infrastructure and gas utilisation,
categorised according to the respective technology (see also [22, 23]). In order to achieve a process chain with
maximum energetic efficiency at reasonable costs while meeting the requirements of the DVGW regulations, it
seems reasonable to feed the hydrogen directly into the natural gas grid, up to the maximum admixing ratio. Only
after exhausting these options, further amounts of excess electricity should be used to produce methane in an
additional step; i.e., by hydrogen production.
[Brennwert = fuel value
Erdgas = natural gas
Nordsee = North Sea
Russland = Russia
Wobbe-Index = Wobbe index]
Figure 4: Maximum admixing ratios of hydrogen in natural
gases [22]
The maximum admixing ratios of hydrogen depend on the characteristics of the natural gas (Figure 4 [22]). There
are good opportunities for the admixture to natural gas L from Dutch sources (in Figure 4 referred to as natural
gas L Holland): Almost 15 vol.% hydrogen may be added to this gas. Up to almost 15 vol.% hydrogen may be
added to the more high-calorific natural gas H from the North Sea (in Figure 4 referred to as natural gas H North
Sea), too. By contrast, the possibilities of adding hydrogen to West Siberian natural gas (in Figure 4 referred to as
natural gas H Russia) are limited to about 3% and are thus much lower. These mixing ratios were determined in
accordance with the regulations for the gas characteristics of fuel gases for public gas supply systems specified by
the DVGW Technical Code Worksheet DVGW G 260 [27], taking into account the limits regarding the standard
volume-related calorific value Hs,n, the relative density d, and the standard volume-related Wobbe index Ws,n.
The study [22] representing the DVGW view thus concludes: "It is to be assumed that the existing natural gas
infrastructure largely lends itself to a content of about 10 vol.% H2 in natural gas." The gas industry is also
considering a modification of the DVGW Worksheet G 260. Limitations with regard to individual areas of
application - for instance in conjunction with gas turbines and natural gas-powered vehicles - are discussed in
Section 4.
The efficiency of the entire process chain from the renewable energy source to the hydrogen fed into highpressure grids varies between 54 and 77%, depending on the technology used as well as the local conditions (for
instance the grid pressure). If hydrogen is further converted to methane, efficiencies between 49 and 65% are
achieved. These results are obtained if the chemical energy stored in H2 resp. CH4 is compared to the primarily
produced electrical energy (see Figure 5 [26, 28 - 30]). The energy efficiency of individual, locally favourable
projects might be increased even further by advantageous use of waste heat for heating or as process heat.
Figure 6 [26, 28 – 30] shows the efficiency chain of electricity generation in a gas and steam turbine (GuD) power
station from hydrogen or methane gas, respectively, that was generated by electricity from wind and solar power.
These somewhat limited efficiency values correspondingly affect the engineering effort needed for power to gas
concepts as well as their specific electricity generation costs.
[Pfad = system
Wirkungsgrad = efficiency
Strom-zu-Gas = power-to-gas
Strom = electricity
Strom-zu-Gas-zu-Strom = power-to-gas-to-power
Strom-zu-Gas-zu-KWK = power-to-gas-to-CHP (combined
heat and power)
KWK = CHP (cogeneration or combined heat and power)]
Figure 5: Efficiency values of power to gas systems [26]
Based on a possible mean hydrogen content of approximately 10% and a natural gas consumption volume in
Germany of approximately 90 billion Nm³/year, about 8 up to almost 9 billion Nm³/a H2 may be admixed. Electrical
energy of 38 billion kWh/a would be required to generate this hydrogen flow. Assuming an optimally high efficiency
of 80%, about 30 billion kWh/a were to be stored as hydrogen in the natural gas grid. Based on the cautious
assumption of a possible average hydrogen content of approximately 5%, or assuming a reduction of the natural
gas consumption in Germany by the year 2050 to 45 billion Nm³/a at 10% H2 content, it may theoretically be
possible to add about 4 to 4.5 billion Nm³/a H2. 19 billion kWh/a of electrical energy would be needed to generate
this hydrogen flow. At 80% efficiency (as assumed), about 15 billion kWh/a would be stored as hydrogen in the
natural gas grid (see also [14]).
Figure 6: Efficiency values of the power to gas chain regarding electricity generation from hydrogen (above)
as well as from methane (below) [26, 28 - 30]
[Erneuerbare Energien = renewable energies
Transformator und Gleichrichter = transformer & rectifier
Druckelektrolyse inkl. Nebenanlagen = pressure electrolysis, including ancillary systems
Verdichter, Speicher, H2-Stichleitung = compressor, storage facility, H2 stub
Transport = transport
GuD = combined cycle
Methanisierung = methanation]
4. H2 tolerance of structural elements in the natural gas grid and of gas consuming technologies
For pipelines in high-pressure, medium-pressure, and low-pressure grids, H2 addition of up to 50 vol.% is
considered to be uncritical. H2 permeation through steel and plastic pipelines, connection technology, seals and
membranes is technically, economically, and ecologically negligible [22].
Existing gas turbine units, however, may be damaged by H2 addition to the natural gas. Thus, depending on the
manufacturer, the H2 concentration in gas turbines is limited to a value between 1 and 5 vol.%. Various
manufacturers are offering new turbines geared toward higher amounts of H2 in the mixture. This is also true of
gas turbines that are used as drive motors of compressors in the natural gas grid. These, however, may be
equipped with a fuel gas methanation unit [22]. Thus, gas grid operators expect significant conversion costs for 5 to
10 vol.% H2 additions to the natural gas [31], especially regarding the compressor stations in their high-pressure
grids that are equipped with gas turbines as drive motors. Corresponding considerations are discussed in the
Netzentwicklungsplan Gas (Gas Network Development Plan) for 2012 [32].
In underground reservoirs - less in cavern gas storage facilities but to a greater extent in pore storage facilities higher H2 contents in the natural gas may stimulate H2S formation by bacteria [22, 33].
Ultrasound, turbine, and diaphragm gas meters are generally considered suitable even for high H2 concentrations.
Volume conversion devices may be used without any restrictions for gas mixtures containing up to 10 vol.% H2 [22].
Today's process gas chromatographs using helium as a carrier gas for gas quality analysis are unable to clearly
detect H2. Since
2013, however, a more sophisticated technology is available which can also analyse the H2 content in
fuel gases [34].
In Germany, pressure regulator stations, valves, domestic installations, and gas flow monitors are designed,
constructed and operated in accordance with the DVGW Worksheet G 260. Thus, there are no limitations to the
hydrogen content, as long as it remains within the limits specified by the DVGW Worksheet G 260 [22].
For decades, domestic gas terminals in Germany have complied with the specifications of the DVGW Worksheet G
260. Even at 20 vol.% addition to the natural gas, hydrogen has no negative effects on today's premix devices in
particular. Older gas appliances, however, may not be suitable for H2 concentrations of more than 10 vol.%. For a
long time, gas appliances have been tested with gases of varying characteristics - including a natural gas with an
H2 content of 12 vol.% [22]. All gas appliances for use in the public gas supply, targeted for the natural gas H
group, are to be tested according to DIN EN 437, using a test gas with an H2 content of 23 vol.% to ensure at least
temporarily safe operation [24].
For gas appliances in the industrial context, practical research regarding emission and efficiency values in actual
applications should be performed to assess the effect of H2 additions of 10 vol.% and more. Assessment of certain
industrial sectors (such as, for instance, the glass and ceramics industry) shows that it is apparently not the H2
content of the natural gas, but rather varying gas characteristics that are at the core of the problem [35] - even if
the H2 content remains within the limits specified by the DVGW Worksheet G 260. The possibility cannot be ruled
out that, for some industrial processes, hydrogen needs to be removed from the fuel gas or an alternative supply
needs to be implemented [22].
As far as natural gas tanks and natural gas filling stations go, [22] points to the need for investigations with regard
to the pressure change loading of the steel tanks used in this context. The current project investigates a number of
questions with regard to materials technology.
No major problems are expected with gas engines at H2 contents of up to 20 vol.%, provided that the enginespecific methane numbers are met. Yet the DIN 512624 provision is very restrictive in that it specifies a maximum
H2 addition of 2 vol.%.
Thus, the current project will also elucidate whether this constraint should be maintained as it is or whether it may
be relaxed. On the positive side, H2 addition expands the ignition limits, increases the flame velocity, and very lean
gas-
air mixtures therefore allow more efficient combustion. For gases with low methane numbers (such as North Sea
natural gas or heavy liquid natural gases), the reduction of the methane number due to H2 addition may be
problematic [22].
5. Electrolysis
Water electrolysis - which is highly exothermic - may be used, for instance, to produce hydrogen from excess
electrical energy. During this reaction, water is converted to hydrogen and oxygen in accordance with the reaction
equation
2 H2O (l) 2 H2 (g) + O2 (g) ∆RH° = + 286 MJ/kmol (Eq. 1).
The molar reaction enthalpy to be added equals ∆RH° = + 286 MJ/kmol. There are primarily two suitable
approaches: alkaline electrolysis (Figure 7) or PEM electrolysis (PEM = proton exchange membrane). Both
reactions may proceed either at ambient pressure or under pressures of up to 30 bar at a temperature between 50
and 80 °C. With modern technology, efficiencies of up to 80% may be obtained [14]. Another water-splitting
technique involves high-temperature thermolysis; although this method is not commercially available [36,
37].
Figure 7: Electrolyser (alkali electrolysis at ambient pressure; electrical power 2 MW; Audi e-gas plant Werlte
[25])
Alkaline electrolysis is the most commonly used technology. The anode and the cathode are separated by a
diaphragm that is permeable for OH- ions. The electrolyte is a KOH solution. To date, PEM electrolysis is only
used on a small scale. The electrolyte is an H+ -conductive solid-state plastic membrane. Currently, the specific
costs are much higher than those of alkaline electrolysis. Potential for improvement still exists in the area of the
lifespan and the service life. This may benefit from pertinent experience regarding further development of the PEM
fuel cell. It is to be expected that values similar to those of alkaline electrolysis may be achieved in the future [38 –
40].
Electrolysis systems must be extremely flexible so as to meet the stringent requirements in this context and to
make up for the considerably fluctuating power generation pattern of wind and solar energy plants with their highly
variable power output. Besides, hydrogen for the grid as well as for possibly required methanation should be
available at pressures in excess of 10 to 20 bar. Owing to its simple system design with a solid-state electrolyte,
which allows better adaptation to higher pressures, the PEM electrolyser seems to provide a sensible technology
to meet these requirements. Besides, the PEM process appears to be more advantageous with regard to the
flexibility required for rapidly varying loads, especially due to its peripherals (for instance for water and gas
cleaning) [14, 38].
6. Methanation
If the limits specified by the DVGW Worksheet G
260 are reached when feeding hydrogen into the natural gas pipelines, hydrogen methanation is required if excess
electricity is available [41 – 49]. In this case, methane may be fed into the gas grid without any limitations. This,
however, necessitates considerable additional technical as well as financial efforts and reduces the overall
efficiency.
The disadvantage is that the two methanation reactions considered in this context are highly exothermic: CO
methanation from a synthesis gas with carbon monoxide and hydrogen as components (equation 2) then the molar
reaction enthalpy is ∆RH° = - 206 MJ/kmol:
CO (g) + 3 H2 (g) CH4 (g) + H2O (g) ∆RH° = – 206 MJ/kmol (equation 2)
If CO2 methanation proceeds from a synthesis gas with carbon monoxide and hydrogen as components (equation
3), then the molar reaction enthalpy equals ∆RH° = - 162 MJ/kmol:
CO2 (g) + 4 H2 (g) CH4 (g) + 2 H2O (g) ∆RH° = – 165 MJ/kmol (equation 3)
The CO methanation reaction requires a solid-state catalyst, for instance a nickel catalyst. Nickel catalysts require
high-purity gas regarding sulphur compounds and oxygen, as well as temperatures of at least 200 to 220 °C.
CO2 methanation may be seen as a combination of CO methanation and CO conversion (equation
4). The CO conversion reaction (Eq. 4) releases a molar reaction enthalpy of ∆RH° = - 41 MJ/kmol:
CO (g) + H2O (g) H2 (g) + CO2 (g) ∆RH° = – 41 MJ/kmol (Eq. 4)
The utilisation the methanation reaction to produce methane resp. SNG from coal-based synthesis gases was
developed in the 1970s to a stage of industrial maturity. The focus by now is not only on synthesis gases from coal
as a raw material, but also on synthesis gases obtained from solid biomass (wood).
The processes and the systems engineering developed since the 1970s (see, for instance,
images 8 and 9) may be categorised as follows, according to [14]:
Figure 8: Methanation unit with fixed-bed
and heat dissipation via
molten salt (e-gas plant Werlte [25])
Figure 9: methanation unit at the centre for reactor
Solarenergie- und Wasserstoffforschung (ZSW)
in Stuttgart [52]
2-phase systems (gaseous raw materials, solid-state catalyst) with a fixed-bed reactor or a fluidized-bed reactor
(state of the art) or with coated combs (large-scale industrial use not yet feasible)
3-phase system (gaseous raw materials, liquid heat transfer medium, solid-state catalyst): with a bubble-column
reactor (state of the art)
Owing to the considerable exothermic reactions, effective dissipation of the high molar reaction enthalpy is of
importance with all these techniques. In 2-phase systems with fixed-bed reactors, several reactors are connected
in series. In between the reactors there are heat exchangers for isobaric cooling. Depending on the process in
question, this involves two to six steps requiring partially complicated system interconnections.
Apart from processes based on fixed-bed gasifiers, 2-phase systems also employ fluid-bed processes. These
require only a single reactor, which makes for a much simpler design. The limited service life of the used catalyst,
however, is somewhat of a drawback. Another methanation procedure involves the use of metallic honeycomb
structures in a 2-phase system [28, 29]. The large-scale industrial utility of this procedure, however, remains to be
elucidated.
Double-phase reactor concepts, according to [14], have the considerable disadvantage that efficient operation is
possible only with sufficient gas flow of the raw materials. If the hydrogen flow from the electrolyser is interrupted as may be expected in view of the considerably fluctuating amounts of excess electricity for electrolysis - the
reactor will rapidly cool down, making it necessary to re-heat the reactor to its operating temperature.
According to [14], this drawback is avoided in the 3-phase system with a liquid heat transfer medium: The solidstate catalyst is suspended in a mineral oil and fluidised by the rising gas bubbles. This procedure was patented in
1976 [48]. A variant of this concept is currently being further developed by the DVGW Research Centre at the
Engler-Bunte-Institut of the Karlsruher Institut für Technologie. The focus in this context is primarily on the good
modelling characteristics and the partial load performance [49].
7. Site analyses: Requirements and conditions at the gas entry points
The specific investment and operating costs of electrolysers as well as the possibly required methanation units
depend largely on the size of the power plants. This is an argument in favour of planning power plants of at least
100 MWel up to several hundred MWel at selected locations [31]; a large number of small, decentralised power
plants, on the other hand, are an economical disadvantage. An optimum site for power plants according to Figure
10 should preferably comply with the following conditions [31]:
-
Access to a high-voltage grid resp. an ultra-high voltage grid.
An environment with a comparatively high density of power plants for electricity generation from wind and
solar energy plants.
Access to a high pressure gas grid with high gas flow rates and even, high capacity utilisation
Access to a water system (optimally to a long-distance water system with a high flow rate)
Availability of CO2 from regenerative sources (for instance from biogas plants) or possibly from nonregenerative sources (conventional thermal power plants, industrial facilities with CO2 emissions)
Usability of waste heat from electrolysis
Existing large-scale technical plants or human settlements in the vicinity requiring process heat or
methanation heat
Existing large-scale technical plants in the vicinity requiring electrolytically produced oxygen
Existing large-scale technical plants or human settlements in the vicinity requiring special process gases,
for instance for in-plant power generation and/or heat generation
It will be impossible to find locations meeting all of these criteria. Preliminary investigations regarding this topic are
described in [31, 50, 51].
H2-Einspeisung = H2 injection
CH4-Einspeisung = CH4 injection]
Figure 10: Technical elements of the power-to-gas concept [26]
[Stromnetz = electricity grid
Windstrom = wind power
Solarstrom = solar power
Andere = other EE
Wasseraufbereitung = water
treatment
Puffer = buffer
Stromeinspeisung = electricity feed-in
Rückverstromung = re-conversion to electricity
Druckregler und Gasspeicher = pressure regulator
and gas storage facility
Gasnetz = gas grid
Industrie-H2 = industrial H2
H2-Tankstelle = H2 filling station
Transformator = transformer
Gleichrichter = rectifier
Elektrolyseur = electrolyser
Gasabscheider = gas separator
Anlage = unit
GDRM = gas pressure control system
Methanisierung = methanation
Gasreinigung und Gastrocknung = gas cleaning & gas drying
Einspeiseanlage = injection unit
[22] shows location analyses characterised by four different conditions, for instance regarding the availability of
excess electrical power, gas feeding options, and - related to these factors - the achievable annual full load hours
of the facilities. Locally possible heat and oxygen use are neglected in this context.
1. Location in Northern Germany with interconnection of several wind parks; the produced gases are fed into a
regional gas pipeline with low typical annual natural gas load flow.
2. Site in Northern Germany with several interconnected large-scale wind parks; the produced gases are fed into
a supra-regional gas pipeline with a high, considerably fluctuating natural gas load flow.
3. Site in North-Eastern Germany with several wind power plants; the produced gases are fed into a regional gas
pipeline with a low typical annual natural gas load flow.
4. Site in South-Western Germany with several photovoltaic systems; the produced
gases are fed into a regional gas distribution grid.
The results show that it might be beneficial to add methane at location 1 and to add hydrogen at locations 2 and 4.
Location 3 allows no beneficial solution, due to the lack of annual full load hours.
Based on a rate of 5 Ct/kWh for the excess electricity used, a profitability analysis in accordance with [22] shows
specific costs of gas generation. At 1200 annual full load hours these costs would be between about 28.2 and 93.9
Ct/kWh and at 7000 annual full load hours, they would be somewhere between about 13 and 26 Ct/kWh. From the
present perspective, these results demonstrate that, for the four cases investigated in this context, there are no
economic conditions for to operation of power to gas systems. According to [22], however, successful market
introduction of this technology may offer greater cost-saving potentials.
8. Pilot projects
A number of test and pilot facilities as well as an industrial-scale power plant for research and development of the
power to gas technology are already being operated or in the planning stage. Some of these power plants are to
be discussed briefly below [52, 53]:
In 2009, the "SolarFuel Alpha" plant went into operation in Stuttgart [54]. It produced up to 25
Nm³ methane per day. A second test facility with a methane generation capacity of 300 Nm³ per day started
operating there in 2012. The facility is operated by Anlagenbauer Etogas GmbH (previously Solarfuel), supported
by the Fraunhofer IWES and the Zentrum für Solarenergie- und Wasserstoffforschung (ZSW).
In 2011, another power to gas test facility was built in Morbach. The operators of this power plant with a power of
up to 25 Nm³ methane per day were SolarFuel GmbH and juwi AG, supported by the municipal authority of
Morbach. This power plant was to create interconnection capacities with a biogas plant for CO2 utilisation. The
power plant has been dismantled.
In 2011, Enertrag AG commissioned their hybrid power plant [55]. This power plant is located Wittenhof near
Prenzlau in Brandenburg. Approximately 120 Nm³/h hydrogen are produced using a 500 kW (alkaline) pressure
electrolyser. Gas storage facilities are available for temporary storage of the produced hydrogen. This power plant
includes a wind farm, an electrolyser, a biogas plant, a combined heat and power plant, and a hydrogen filling
station. There is no methanation of the produced hydrogen. Using the hybrid power plant, it should be possible to
refine the load forecasting - an important parameter for the management of electricity grids - so far that the
deviation of the actual power generation from the desired power generation is reduced to a minimum. In the long
run, this is to allow demand-based sales of renewable energy and its use as so-called balancing energy to make
up the energy shortfall caused by fluctuating demand and supply in the electricity grid.
Figure 11: Power-to-gas unit RH2-WKA in Grapzow [56]
The "RH2-Werder/Kessin/Altentreptow“ (RH2-WKA) wind farm is a land-based wind farm with an installed
electrical power of 140 MW in the Grapzow municipality in Mecklenburg-Vorpommern (Figure 11). Since 2011, it
has been equipped with an integrated hydrogen production plant as well as a combined heat and power plant with
an electrical power of 250 kW. The RH2-WKA project aims at the setup and operation of a wind farm as a socalled "regenerative backup power plant" for optimum grid integration of renewable energy. This wind-hydrogen
system with an electricity feed-in power of 500 kW and an H2 generation capacity of 120 Nm3/h discontinuously
stores available wind energy at any given time, to be released evenly as electrical power at a later point in time,
whenever it is required [56].
In 2013, the "SolarFuel Beta plant" built by Etogas GmbH (images 3, 7, and 8) went into operation in conjunction
with the "g-tron" project of Audi AG in Werlte / Emsland. This plant is to attain CO2-neutral mobility. To this end,
excess electricity from sea-based wind power plants owned by Audi AG is used to produce hydrogen (H2) using
three alkali electrolysers. In a tube - fixed bed reactor, synthetic methane is produced from H2 and CO2 and fed
into the gas grid. As of 2014, owners of natural gas-powered vehicles who are participating in this project may
purchase so-called "e-gas" as an additional package at conventional natural gas filling stations. The CO2 that is
required for methanation is supplied by a waste biogas plant of EWE Energie AG, on whose premises the powerto-gas plant is operated. This plant, with its 6.3 MW electrical power supply and a methane gas generating facility
of about 3.900 Nm³/h, is the first industrial-scale power plant. The desired efficiency is about 54% [25, 57].
In 2013, the energy utility company E.ON AG started up its own power-to-gas pilot plant in Falkenhagen
(Brandenburg) (Figure 12). By alkaline electrolysis, the power plantproduces about 360 Nm³/h H2from
regenerative power, which is fed into the natural gas grid (admixed). The electrolyser of the power plant is directly
connected to the electricity grid. The Falkenhagen location was selected primarily because of the readily available
power and gas infrastructure in the vicinity as well as the wind parks situated in the area [58].
Figure 12: E.ON power-to-gas plant in Falkenhagen [58]
At the company's own brown coal power plant site in Niederaußen, RWE Power AG is operating a hydrogen
methanation plant. At this plant, operational questions in conjunction with power plants of this type are investigated
[59]. This project is connected to another power-to-gas initiative named "CO2rrect", which is supported by 15
partners from the chemical industry, the energy industry, and science. "CO2rrect" stands for "CO2 reaction using
regenerative energies and catalytic technologies".
In Ibbenbüren in the Münster region, RWE Germany AG is building a power-to-gas demonstration plant for the
storage of electricity. In the power plant with an electrical power of 100 kW, the PEM electrolysis technology
developed by the French company Ceram Hyd is being tested. The hydrogen produced in this plant is fed into the
regional RWE gas grid and, using heat and power cogeneration, may be re-converted to electricity if needed. This
is to prove that the used technology can cover the power gradients in conjunction with electricity generation from
wind and photovoltaic units in partially intermittent operation, thus contributing to the system integration of
regenerative electricity generation [60].
9.
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