Iea bioenergy 2014

A perspective on the potential role
of biogas in smart energy grids
Tobias Persson, Jerry Murphy,
Anna-Karin Jannasch, Eoin Ahern,
Jan Liebetrau, Marcus Trommler,
Jeferson Toyama
SUMMARY
This report documents the potential role of biogas in smart energy grids. Biogas systems can
facilitate increased proportions of variable renewable electricity on the electricity grid through
use of two different technologies:
• Demand driven biogas systems which increase production of electricity from biogas
facilities at times of high demand for electricity, or store biogas temporarily at times of
low electricity demand.
• Power to gas systems when demand for electricity is less than supply of electricity to
the electricity grid, allowing conversion of surplus electricity to gas.
The report is aimed at an audience of energy developers, energy policy makers and academics
and was produced by IEA Bioenergy Task 37. Task 37 is a part of IEA Bioenergy, which is one of
the 42 Implementing Agreements within IEA. IEA Bioenergy Task 37 addresses the challenges
related to the economic and environmental sustainability of biogas production and utilisation.

Smart energy grids IEA Bioenergy
A perspective on the potential role of biogas in smart energy grids
Technical Brochure prepared by:
Tobias Persson, Jerry D Murphy, Anna-Karin Jannasch, Eoin Ahern,
Jan Liebetrau, Marcus Trommler, Jeferson Toyama
Edited by David Baxter
Published by IEA Bioenergy
Disclaimer
IEA Bioenergy, also known as the Implementing Agreement for a Programme of Research, Development and Demonstration on Bioenergy, functions within a Fra-
mework created by the International Energy Agency (IEA). Views, findings and publications of IEA Bioenergy do not necessarily represent the views or policies of
the IEA Secretariat or of its individual Member countries.
Copyright © 2014 IEA Bioenergy. All rights reserved.
First printed edition produced in 2014
A catalogue record for this Technical Brochure is available from the British Library.
ISBN 978-1-910154-12-0 (printed paper edition)
ISBN 978-1-910154-13-7 (eBook electronic edition)

Smart energy gridsContent
03
Contents 3
Foreword 4
1. Introduction 5
1.1. The challenge to substitute fossil fuels 5
1.2. Biogas as a facilitator for increasing intermittent renewable electricity 6
1.3. The potential of the natural gas grid to store energy 6
1.4. The limited role of hydrogen in power to gas systems 7
1.5. End use of biogas 7
1.6. Objectives of report 7
2. Development of electricity generation in selected IEA countries 8
2.1 Germany 8
2.2 Sweden 8
2.3 Republic of Ireland 9
2.4 Brazil 9
3. Demand driven biogas plants to stabilize the electricity grid 10
3.1 Economic incentive for demand driven biogas 10
3.2 Biomethane: a route to energy storage 10
3.3 Co-operative approach to demand driven biogas 11
3.4 Demand driven biogas at a single facility 11
3.5 Case study: Sobacken biogas plant 12
3.6 The benefit of combining phased feeding with biogas storage 13
3.7 Biomethane storage through pressure variation in the distribution grid 13
3.8 Complexity and efficiency loss in demand driven biogas systems 14
3.9 Flexible bioenergy in the energy grid 14
4. Power to Gas; a means of storing surplus electricity 15
4.1 Electrolysis 15
4.1.1 Alkaline Electrolysis Cells (AEC) 15
4.1.2 Polymer Electrolyte Membrane cells (PEM) 15
4.1.3 Solid Oxide Electrolysis Cells (SOEC) 16
4.2 Power to methane 17
4.3 Catalytic methanation 18
4.4 Biological in-situ or ex-situ methanation? 19
4.4.1 Sequential processes of anaerobic digestion 19
4.4.2 Effects of adding H2 to an anaerobic reactor 19
4.4.3 Biological methanation in the anaerobic biogas reactor (In-Situ Reactor) 20
4.4.4 Biological methanation in a separate reactor (Ex-Situ Reactor) 20
4.5 Can biogas upgrading be replaced by methanation? 21
5. Discussion 22
6. Conclusions and recommendations 24
References 25

04
Smart energy grids Foreword
Acknowledgements
The authors are grateful for the support from John Bøgild Hansen (Haldor Topsoe), Dominic Hofstetter (Electro-
chaea), Filip Smeets (Hydrogenics), Martin Ragnar (Energiforsk, Sweden), Camilla Till (Borås Energi och Miljö AB),
Paul Deane (Environmental Research Institute) and Mathieu Dumont (Netherlands Enterprise Agency) for providing
useful information for this publication.
Foreword
This publication describes a perspective on the
potential role of biogas in meeting fluctuating demand
for electricity, and in smart energy grids. The amount of
variable renewable electricity produced in the world is
rapidly increasing and so is the need to develop suitable
technologies to balance uneven electricity production
and utilisation. Demand driven biogas plants allow
electricity generation specifically at times of peak
electricity demand. Power to gas systems allow any
surplus electricity to be converted to hydrogen at times
of low demand. Power to gas systems can generate
gaseous biofuel for transport (or for heat) from
electricity that is in excess of demand, for example in
regions with very high generation capacity from inter-
mittent sources such as wind and solar.
It is shown that biogas:
• can be used to facilitate increased variable
renewable electricity on the grid
• systems can be used to increase electricity
production at times of low supply
And that:
• Power to gas systems convert electricity to
storable gas when demand for electricity is low
• Power to methane systems can act as a means
of upgrading biogas to biomethane
Biogas production systems have significant potential
to facilitate increased proportions of variable renewable
electricity in an integrated energy system. This is
implemented either by demand driven biogas systems
or through power to gas systems. Biogas systems
typically produce electricity at a relatively uniform rate,
unlike variable renewable electricity such as produced
by wind turbines. Demand driven biogas plants can
increaseelectricityproductionattimesof highelectricity
demand and can reduce electricity production at times
of low demand. This can be achieved through storing
biogas and only using it to generate electricity when
needed by the grid. This managed fluctuation of
electricity production can be enhanced through varying
the time, and rate, of feeding of the biogas plant.
Power to gas systems have a totally different role. In
essence these systems involve converting electrical
energy into gas that can be more readily stored. At times
of low demand for electricity, electrolysis may be
employed to convert surplus variable renewable
electricity to hydrogen. Hydrogen is an energy vector of
the future; the hydrogen infrastructure is not yet in
place. Hydrogen may subsequently be converted to
methane by catalytic or biological methanation. The
methane may be used as a source of renewable gaseous
transport fuel or renewable heat.
A model is proposed which combines these two
concepts at biogas facilities allowing storage of variable
renewable electricity, with co-production of electricity
(at times of peak demand for electricity) and methane
for gas grid injection (at times of low demand for
electricity).
The authors of this report are members of IEA
Bioenergy Task 37, which addresses the challenges
relatedtotheeconomicandenvironmentalsustainability
of biogas production and utilisation. IEA Bioenergy is
one of 40 currently active Implementing Agreements
within the International Energy Agency and has the aim
of improving cooperation and information exchange
between countries that have national programmes in
bioenergy research, development and deployment. IEA
Bioenergy’s vision is to achieve a substantial bioenergy
contribution to future global energy demands by
accelerating the production and use of environmentally
sound, socially accepted and cost-competitive bioenergy
on a sustainable basis, thus providing increased security
of supply whilst reducing greenhouse gas emissions
from energy use.

Smart energy gridsIntroduction
05
1. Introduction
The aim of this report is to outline the potential role
of biogas in stabilising the electricity grid in a future
where more variable renewable electricity will be
produced, for example from wind and solar. This report
will not describe the technologies in detail, but instead
present an overview of current technologies and a per-
spective on applications of biogas technologies for
balancing electricity supply with demand in future
smart grids. According to IEA (IEA, 2011), a smart grid
is an electricity network that uses digital and other
advanced technologies to monitor and manage the
transport of electricity from all generation sources to
meet the varying electricity demands of end-users.
Smart grids co-ordinate the needs and capabilities of all
generators, grid operators, end-users and electricity
market stakeholders to operate all parts of the system as
efficiently as possible, minimising costs and
environmental impacts while maximising system
reliability, resilience and stability.
This report presents various options for demand-
driven biogas plants and power to gas. A model of an
integrated demand driven biogas, power to gas system is
proposed whereby increased electricity can be generated
at times of peak demand while at times of low demand,
electricity can be used for the production of biomethane
which can be injected into the gas grid or used as a
gaseous renewable transport fuel.
1.1. The challenge to substitute fossil fuels
Climate change is the major driver for renewable
energy technologies. The challenges for engineers and
scientists include the development and selection of the
best available technologies and integration of these
technologies into the existing energy infrastructure.
Energy systems will need to undergo dramatic changes
to allow compliance with renewable energy targets and
proposed reductions in greenhouse gas emissions. Fossil
fuels will eventually have to be phased out; this however
is not an easy task. Fossil fuels are still relatively cheap;
for example fracking has significantly increased the
resource of natural gas in the USA and reduced the pri-
ce of gas. Power plant technologies are very well proven
and efficient; natural gas combined cycle gas turbines
(CCGT) can produce electricity at conversion efficien-
cies in excess of 60%. Most importantly fossil fuels can
provide a constant reliable output of electricity. This is
a challenge for renewable electricity, in particular when
sourced from wind and solar, as the production tends to
be variable or intermittent. As the portion of variable
renewable electrical energy increases in the electricity
supply system, it becomes very difficult to match pro-
duction with demand. The potential for oversupply
(and lower prices for electricity), and more crucially,
undersupply (leading to outages) increases with
increased levels of variable renewable electricity.
It is necessary to balance electricity supply and
demand (or load) at all times within a defined electro-
technical framework; voltage stability is required for the
protection of technical facilities. The
balancing requirement is often at distri-
bution grid level (low and medium
voltage); this provides new opportuni-
ties for flexible energy supply and/or
demand side management.
The question of how to deal with a
high share of variable renewable power
production (such as solar and wind)
has to be addressed at TSO (transmissi-
on system operator) and DSO (distri-
bution system operator) levels. Within
the TSO networks a major balancing
can be achieved through interconnec-
tors between countries. The TSO-grids
are often 110/380kV voltage grids. At
Figure 1: Comparison of various energy storage systems with respect to discharge time
and storage capacity (modified from Specht et al., 2011).

this level, base load from big nuclear or fossil power
plants feed into the grid. The DSO network distributes
the energy from TSO networks to the customers. These
grids are required to accept electricity feed in from rene-
wable electricity production. This is challenging for the
network operators, since the network was not originally
built for the feed in of high shares of renewable electri-
city, but only for energy distribution. This can lead to
reverse load flow between low and medium voltage
levels, as well to overloads of network equipment or
critical grid situations when operating parameters are
not met.
Typically, electricity storage mechanisms include:
flywheels; batteries; compressed air energy storage
(CAES); pumped hydroelectric storage (PHS) and heat
pumps in houses. These options are limited by short
duration time of storage (Figure 1).
1.2. Biogas as a facilitator for increasing
intermittent renewable electricity
Biogas systems can facilitate increased variable
renewable electricity on the grid. One such system is
demand driven biogas (Figure 2(a)). This is very rele-
vant in countries such as Germany with an extensive
biogas infrastructure. These plants may be operated in
such a way as to increase production of electricity from
biogas when the demand for electricity is high. This
may be implemented by storing biogas until electricity
demand is high and/or by feeding biogas plants in a
pulse mode that produces maximum biogas output
when electricity demand is high.
A second system is termed Power to Gas (Figure
2(b)). This involves converting renewable electricity to
hydrogen (H2) using electrolysis when the electricity
production is high but demand is low. However the
infrastructure and industry associated with hydrogen as
a transport fuel, or as an energy vector, has yet to be
widely employed. Distribution systems or end users are
not in place. However the methane economy is mature
and many countries have extensive natural gas
(methane) distribution systems and methane end use is
widespread, ranging from home heating to natural gas
vehicles (NGVs) to combined cycle gas turbine power
(CCGT) plants. The hydrogen can be used to produce
methane (CH4) through methanation in two ways: cata-
lytic conversion or biological conversion. Both of these
technologies will be explored in this report. Methane
produced from surplus electricity via hydrogen may be
injected to an existing gas grid; this allows for storage of
the energy and also changes the energy vector from
electricity to gas. The storage capacity and duration of
storage of methane is in well in excess of most other
energy storage systems (Figure 1).
The renewable gas (or green gas) can be used for
renewable heat, as a renewable transportation fuel, or as
a source of renewable electricity when demand increases
again. Hence, this integration technology is a potential-
ly key component of a future smart grid.
1.3. The potential of the natural gas grid to
store energy
The existing natural gas grids have distributed natu-
ral gas since the 1950s and 1960s. The extensive gas
distribution network in existence today also provides
for large scale energy storage in the grid itself as well as
through the connection to below-ground storage
systems such as salt caverns and depleted gas reservoirs.
The global working gas storage capacity for natural gas
is about 319 billion normal m³ (STP: normally referred
to in the biogas and biomethane sectors as Nm3) with
more than 690 storage systems worldwide, of which
two-thirds are situated in Russia and USA (LBEG,
2013). This storage capacity could potentially be utilized
in power to gas systems. In power to methane systems,
the produced methane can be injected into the gas grid
for storage and/or associated storage systems. In terms
of composition or quality there is little difference
between methane from power to methane and natural
gas in the grid; both are dominated by methane even
though natural gas may have small quantities of higher
hydrocarbons such as ethane (C2H6), propane (C3H8),
butane (C4H10) or pentane (C5H12). These higher
hydrocarbons increase the energy value of natural gas.
In several countries, such as Denmark, France and
Germany, investigations have been performed that
indicate that the natural gas grid is a very good option
for storage of energy (Urban, 2013; Larsen and Petersen,
2013; Specht et al., 2011).
06
Smart energy grids Introduction

1.4. The limited role of hydrogen in power to
gas systems
Hydrogen gas could also be fed into the existing gas
grids to form a mixture of natural gas and hydrogen;
this may be termed hythane. By injecting hydrogen into
the grid, the volumetric energy density of the gas is
reduced since hydrogen has a lower heating value
(LHV) of ca. 10.2 MJ/Nm3 compared with CH4 with a
LHV of ca. 35.5 MJ/Nm3. The limitation in injecting H2
to the natural gas grid is the low molecular weight and
the potential for leakage of the H2 from the pipework.
Discussion prevails as to what portion of hydrogen
addition would be acceptable in the gas grid. No defini-
te answers are given in a European context, but a range
from 2 to 20% is discussed. Use of compressed natural
gas, with composition of H2 in excess of 2%, may lead
to corrosion in the high-pressure storage tanks of natu-
ral gas vehicles (NGVs). This may be a practical limit to
hydrogen injection to the grid. From a historic perspec-
tive, it is of note that hydrogen-rich town gas once
dominated the gas market. The first commercial town
gas facilities were in Baltimore, USA (1806) and London
(1813). These systems lasted well into the 1960s. As
such, it is clear that hydrogen may be transported in the
natural gas grid in low proportions and used for any
purpose for which methane is used (e.g. heat, transport
or electricity).
1.5. End use of biogas
The output of power to gas systems includes gas
which may be used as a renewable gaseous transport
fuel. This option can be attractive in Europe due to an
amendment to the Renewable Energy Directive (RED,
2009) which allows double counting of energy used in
the transport sector even when the gaseous fuel is deri-
ved from non-biological origins (such as power to gas).
The double counting is part of the assessment for mee-
ting the 2020 renewable energy supply in transport
(RES-T) target (European Commission, 2014).
Another output is renewable electricity. The effici-
ency of conversion to electricity obviously has a signi-
ficant impact on the overall efficiency of the energy
balancing system. One of a range of power generation
units can be used to produce electricity at a single bio-
gas facility; these include four-stroke engines, micro
turbines and Stirling engines (Kaparaju and Rintala,
2013). These have electrical efficiencies in the range
25-45%. Alternatively, if biomethane is added to the gas
grid from numerous facilities, a large scale combined
cycle gas turbine (CCGT) can achieve electrical efficien-
cy above 60%. In any case, the electricity generation
system must be capable of responding rapidly to chan-
ges in the variable electricity production from solar and
wind. Gas engines can be started within seconds. A
CCGT can start-up and reach full capacity within an
hour (Kaparaju and Rintala, 2013).
1.6. Objectives of report
This report has the objecti-
ve of providing a perspective
on the role biogas can play in
balancing the electricity grid.
When electricity demand is
high, demand driven biogas
concepts can be employed to
increase electricity output
(Figure 2 (a)). When intermit-
tent renewable electricity pro-
duction exceeds demand,
power to gas systems may be
used to convert electricity to
methane (Figure 2(b)).
Smart energy gridsIntroduction
07
A Electricity shortage: Demand driven biogas
production for electricity production
B Electricity surplus: Power to gas systems
using H2 (from electricity) to react with CO2
in biogas to generate biomethane
Figure 2: The role of biogas in the smart grid.

2. Development of electri-
city generation in selected
IEA countries
2.1 Germany
The greenhouse gas emission target of the German
government is 40% reduction from the 1990 level by
2020. The target rises to 55% by 2030 and to 80-95% by
2050. This is coupled with a target of 60% renewable
energy in final energy consumption by 2050 and 80%
renewable energy in final electricity consumption by
2050. Presently the share of renewable energy in electri-
city is around 22%. In Figure 3 it is shown that even at
this level of renewable electricity, at times the renewable
electricity production approaches the electricity con-
sumption level. If the share of renewables is increased
four times (as projected for 2050) it is clear that it will
be hard to match consumption and production without
the introduction of new technologies that can make
good use of surplus electricity.
2.2 Sweden
Sweden is remarkable in that it has a very low car-
bon footprint in electricity production. Electricity in
Sweden is sourced from hydroelectric power (45%),
nuclear power (39%), CHP (11%) and wind (4%). Most
hydroelectric power plants were built between 1910 and
1980. The nuclear power plants were built between 1972
and 1985. Although new investments are made in both
nuclear and hydro-electric facilities on a regular basis,
the fact that the capital investment for the bulk of this
infrastructure was made a long time ago means that the
cost of electricity production in Sweden is low compa-
red to most other countries; 40 EUR/MWh is a typical
figure.
Nuclear power provides a constant base of electrici-
ty production whilst the hydroelectric power is a very
flexible asset for power regulation. As wind power
makes up a small share of the total power production,
power regulation on a national level is uncomplicated.
However, wind power is growing rapidly and nuclear
power could diminish in time. In addition, regional
differences exist. For example on the isle of Gotland,
08
Smart energy grids Development of electricity generation in selected IEA countries
Figure 3. Generation and consumption of electricity in Germany in July 2014, also showing actual electricity consumption and electricity prices
(Note: Regenerative Power includes renewable electricity from solar, wind, biomass and water) (Source: Agora Energiewende).

located in the middle of the Baltic Sea, wind power pro-
duction is substantial and power cables so far only allow
power to be transported from the mainland, not in the
other direction.
Looking forward, Sweden’s electricity production is
already highly de-carbonised. Electricity price rises are
hard to foresee in the next 10 years. The only threat of
instability to Sweden is if it increases integration with
European electric grids such that the regulatory func-
tion of the Swedish hydroelectric power is used for the
benefit of other countries, and consequently lessening
its capability to stabilise the Swedish grid.
2.3 Republic of Ireland
Ireland is an island off the west coast of Europe. This
does not facilitate full integration of electricity distribu-
tion and production with its neighbours. Variable rene-
wable electricity is much more challenging in an island
grid (as on the isle of Gotland in Sweden).
The European Renewable Energy Directive (RED,
2009) set a target for the Republic of Ireland (hereafter
termed Ireland) of 16% renewable energy share (RES)
of gross energy consumption in 2020. The target is
effectively equivalent to a combination of three national
renewable targets of 40% renewable energy supply in
electricity (RES-E), 12% renewable energy supply in
heat (RES-H) and 10% for renewable energy supply in
transport (RES-T).
Ireland’s renewable energy supply was on track to
meet targets as of 2012. In 2012, renewable energy was
responsible for 7.1% of Ireland’s gross energy consump-
tion. This may be broken down as follows.
• RES-E (normalised) reached 19.6% of gross
electricity consumption; the target for 2010
was 15%.
• RES-H was 5.2% in 2012; Ireland’s target
for 2010 was 5%.
• RES-T (including doubling counting for
sustainable biofuels) was 3.8%; Ireland’s target
was 3% by 2010.
Electricity production from wind energy has
increased to the point that it accounted for 81% of the
renewable electricity generated in 2011. This fell back to
74% in 2012 due to the lower wind resource relative to
2011. Electricity generated from biomass accounted for
8% of renewable electricity in 2012. Biomass consists of
contributions from solid biomass, landfill gas, energy
from waste and biogas. Wind, hydro and biomass-
generated electricity in 2012, respectively, accounted for
15%, 3% and 2% of Ireland’s gross electricity consump-
tion.
Looking forward, a study on the Irish electricity
system (McGarrigle et al., 2013) found that the system
non-synchronous penetration limit (related to the abi-
lity to operate the electricity grid with a given percenta-
ge of capacity on the grid from wind turbines) is expec-
ted to be 75% in 2020; in 2014 it was 50%. If this limit
can be increased to 75% by 2020 it would necessitate 7%
of renewable electricity to be curtailed (or be deemed
surplus) by 2020. If this limit can only be increased to
60% then 14% of renewable electricity would need to be
curtailed. Ireland needs to find a means of storage of
this electricity and power to gas presents one such
solution.
2.4 Brazil
Historically, hydro-electricity has represented the
major part of the installed capacity in Brazil. However
more recently, investments have been made in power
plants fueled by natural gas and biomass. In 2013, 68%
of electricity was sourced from hydro-electricity, 28%
from thermal power plants (using natural gas and bio-
mass), 2% from wind, 2% from nuclear power and a
minor amount from solar-photovoltaic generating
plants (ANEEL, Brazilian Electric Energy Regulatory
Agency, 2014). Any negative impact on electricity prices
are hard to foresee due to the high share of hydro-elec-
tric power.
The system of production and transmission of elec-
tric power in Brazil has multiple owners. By the end of
2020, the basic electrical transmission grid will have
142,000 km of power line (Ministry of Mines and Ener-
gy, 2011). The Brazilian Interconnected System (SIN) is
a complex hydro-thermal system that is connected by a
long transmission grid. Currently, only 2% of electricity
production is not part of the SIN; these are isolated
systems located mostly in the Amazonia area.
Smart energy gridsDevelopment of electricity generation in selected IEA countries
09

10
Smart energy grids Demand driven biogas plants to stabilize the electricity grid
The operation of the Brazilian Electric Sector (BES)
is highly regulated. The maximum supply of hydro-
electricity is obtained by retaining the highest level in the
reservoir. Due to the preponderance of power plants in
the BES, mathematical models are used to find the opti-
mal solution to balance the current benefit of water use
and the future benefit of storage, measured in terms of
expected fuel economy of thermal power plants.
To ensure optimal operation of the BES water is
sometimes bypassed through smaller power plants to
keep a stable water level in the dam of Itaipu (second
largest hydro-electric power plant in the world). It
would be possible to use this water in a more efficient
way by producing hydrogen instead of just bypassing the
power plant (see Figure 4). The power to gas concept
could allow for balancing the water levels behind Brazil’s
dams in the future.
3. Demand driven
biogas plants to stabilize
the electricity grid
3.1 Economic incentive for demand driven
biogas
For stable operation of electricity grids it would be of
great benefit to be able to produce biogas and more
importantly, electricity from the biogas at times best
suited to the fluctuating electricity supply from wind
and solar sources. However, for this to happen, there
must be an economic driver for the biogas plant opera-
tors. Existing feed-in tariffs in several European coun-
tries ensure equal incomes for a producer of renewable
electricity independent of whether the generated electri-
city is required at a specific time or not. This is not an
optimal system, especially as levels of installed capacity
of variable renewable electricity generation continue to
increase; this potentially may lead to over supply at times
of low demand, or vice-versa. It can be strongly argued
that the support systems should be adapted to benefit
producers who adjust the rate of electricity production
according to periods of high demand or according to
specific needs of the electricity grids.
3.2 Biomethane: a route to energy storage
Biogas produced through anaerobic digestion is
often used as a source of combined heat and power
(CHP), as shown in Figure 5(A). This is the dominant
use of biogas in most countries, for example in Germany,
South Korea, the UK and Denmark, amongst others.
However Denmark’s near neighbour Sweden uses the
majority of the biogas produced as a source of transport
fuel (Murphy et al., 2004, Persson and Baxter, 2015). For
use as a transport fuel, or for natural gas grid injection
(Urban, 2013), biogas must be cleaned (Petersson, 2013)
and upgraded (Beil and Beyrich, 2013) to typically
greater than 97% methane content (then known as bio-
methane). Inserting the biomethane into the natural gas
grid allows for storage of the methane and later use as a
fuel for heat, transport fuel or for power generation at
times of peak demand, as shown in Figure 5(B). Another
Figure 4. Water being bypassed at the hydro-electric power plant in Itaipu
with a capacity of 14GWe

Smart energy gridsDemand driven biogas plants to stabilize the electricity grid
11
advantage is that the biomethane can be used to genera-
te electricity in combined cycle gas turbines that can
produce electricity from methane with efficiency above
60%. In Germany over the last few years a significant
number of biogas facilities chose to inject gas into the
gas grid (Bowe, 2013). However, CHP fed with raw bio-
gas is still dominant in Germany.
3.3 Co-operative approach to demand driven
biogas
Optimized electricity supply from renewables is the
business case of some new companies in the electricity
market in Germany since 2012. These power traders
have developed portfolios of mainly renewable capaci-
ties comprising a lot of wind and solar power, but also
biogas and fossil-based CHP. With the growth of a sub-
stantial share of renewables in Germany, the influence of
renewables on power market prices has also grown.
Consequently, a higher demand for flexibility in the
power markets has evolved. Today the renewable electri-
city pools of these traders are offered on different power
markets, especially the day ahead and intraday markets.
In addition, balancing power, particularly secondary
control reserve and minute reserve are also provided.
Since 2014 even primary control reserve has been offe-
red by one company. Thus these new players are taking
over some of the functions of providing grid stability
and security of energy supplies, which today is in large
part supplied by fossil energy providers.
In cooperation with Ökostrom, Switzerland, several
biogas plants are connected through a centralised con-
trol and regulation system. This system controls all CHP
units so that the electricity production is adjusted to the
actual electricity demand from one central location
instead of at each individual plant (Mutzner, 2013). By
connecting several units in such a joint control system
the possibility of synchronising all biogas plants to pro-
duce electricity at peak demand times can be optimized.
3.4 Demand driven biogas at a single facility
Research and development is underway, particularly
in Germany and Switzerland, to study the possibility of
varying the rate of production of biogas to match
demand of the electricity from the grid (Jacobi et. al.,
2013; Mutzner, 2013). The concept is to operate CHP
units and produce electricity when electricity is required
and avoid production when demand is low.
Flexible electricity generation is possible by adju-
sting different components and operational strategies.
The biogas plant can shift the time when it combusts
biogas in the CHP, typically by a number of hours. As a
result the biogas plant can adjust the time of production
of electricity to the actual need of the electricity grid
(Figure 6). The gas production rate, the gas storage
capacity and the gas utilization rate define the flexibility
of the plant. This flexibility always requires the storage
of biogas but the gas storage capacity can be reduced if
adjustment of the biogas production process provides
additional flexibility. Demand driven power supply
from biogas plants requires an increased capacity of the
CHP unit in relation to the average output of the plant.
The higher CHP capacity allows a plant to meet periodic
higher than average electricity
demand. It is noted that bio-
methane plants which inject
upgraded biogas into the gas grid
do not need separate gas storage,
although a small storage may be
suitable when services at the
upgrading or injecting facility are
necessary.
Another possibility to vary
biogas production is to utilise two
phase digestion (Nizami & Mur-
phy, 2011) whereby liquors rich in
volatile fatty acids are produced
A Heat and power produced from biogas
B Biogas upgraded to biomethane, gas grid injected
and electricity produced from biomethane off-site
Figure 5: Two different pathways (A-B) for the role of biogas during electricity shortage.

12
in the first phase through hydrolysis and acidogenesis.
Subsequently, the liquor is sent to a separate high rate
methanogenic reactor at times of peak electricity
demand.
3.5 Case study: Sobacken biogas plant
Loading of substrate to the reactor can be limited to
particular times; for example feeding once per day to
achieve high gas production during the daytime (and
when demand is high) and a low gas production
during the night (and when demand is low).
Such a system has been in stable operation in the
Sobacken biogas plant in Borås in Sweden since
2008. The substrate (source separated food waste
and waste from the food industry) is fed to the
digester in a discontinuous manner. The actual
reason for this is not specifically to vary the gas
production, but instead to fulfil the requirement
for hygienisation, the process of minimising
health risks from residues from the biogas pro-
duction process. However, it is an excellent
example of a full scale plant where the biogas
production has been varied significantly each day
while being able to maintain stable operation for
6 years.
The 24 hour daily cycle adopted at the Sobac-
ken biogas plant is as follows. Every morning, at
seven o’clock the flow of fresh substrate injection
into the digester is started and this process is continued
for ten hours. Thereafter, feeding is stopped and nothing
is either injected or discharged for ten hours in order to
allow for hygienisation to take place. During the final
four hours in the 24 hour period digestate is discharged
from the digestion vessel until the starting volume of
digesting liquor in the digester is reached, i.e. the same
volume as at the start of the 24 hour period. The volume
of digestate in the digester and the biogas production
rate are illustrated in Figure 7.
Figure 6: Approaches for biogas-based demand driven power production (Szarka et al, 2013)
Figure 7: Biogas production and feed injection during a 48 hour period at Sobacken biogas plant in
Borås. (Source: Borås Energi och Miljö)

Smart energy gridsDemand driven biogas plants to stabilize the electricity grid
13
The dashed black line in Figure 7 shows how the
substrate volume varies in the digester during one day
between 2900 and 3020 m3 (total effective volume is
3200 m3). The solid line shows how the raw gas produc-
tion varies between 100 and 450 m3/h during the same
day with the highest production in the middle of the
day. The methane concentration in the biogas varies at
the same time between 63% and 72%. This disconti-
nuous operation of the process has not disturbed the
microbiology performance in the digester to an extent
so as to create a problem. Previously, the cycle was shor-
ter and the loading was performed more rapidly which
resulted in operational problems. One challenge that
the operator has observed is that the operation is more
challenging when gas production is high as several units
are operating at the maximum of their capacity. Opera-
tional problems at maximum output are extremely
costly as significant energy revenues can be lost. Uneven
gas quality and the uneven gas flow have created opera-
tional problems for the downstream biogas upgrading
unit based on water scrubbing technology. If a plant is
operated in this way it is important to select a biogas
upgrading system that is able to handle rapid changes in
the gas flow rate as well as in the gas composition.
3.6 The benefit of combining phased feeding
with biogas storage
Research results from Germany indicate that flexibi-
lity of biogas production can lower the need for additio-
nal gas storage capacity or increase the flexibility within
the limits of plants designed to operate under constant
conditions. The result is reduced costs for the provision
of the flexible energy output (Trommler et al, 2012).
However, this approach requires additional operational
effort; feeding needs to be controlled to adjust the gas
production process. In future scenarios the plant opera-
tor will require sufficient process control options to
allow for flexible gas production according to the ener-
gy demand and flexible feeding regimes (Liebetrau et al,
2014). Figure 8 shows the potential reduction of biogas
storage capacity for a flexible biogas production process
(Jacobi et al, 2014a).
3.7 Biomethane storage through pressure
variation in the distribution grid
Upgrading of biogas to biomethane, and production
of electricity in a CHP-unit linked to the gas grid,
increases flexibility of electricity output, due to the gas
storage within the natural
gas grid (Figure 5(B)).
The storage capacity in
the transmission grid is
usually very large, but if
the biomethane is injected
into a distribution grid
the storage capacity is
often limited. A method
of increasing the storage
capacity in the distributi-
on grid is to vary the pres-
sure; use a lower pressure
when the demand for
electricity is high and a
high pressure when the
demand for electricity is
low and the biomethane
needs to be stored. Such a
system was assessed by
Stedin in the Netherlands.Figure 8: Cost reduction by means of lower gas storage need based on flexible biogas production
(Jacobi et al, 2014a)

14
Since 2012 Dutch DSO (distribution system opera-
tor) Stedin has performed field tests with dynamic
pressure management. The principle is to apply variable
pressure levels in the nominal 8 bar natural gas trans-
port grid in order to create additional space for feed-in
of pipeline quality biomethane and to reduce gas trans-
port losses. The concept is called “Smart Green Gas
Grid”, or SG3. The ambition of the work is to solve the
problem of mismatch between local gas production and
local gas demand. After a thorough theoretical analysis,
SG3 was applied in the Netherlands. Real time informa-
tion on pressure levels and gas flows were followed live
on the internet. When the biomethane producer was
offline, extra gas was fed into SG3 from the standard 8
bar gas grid. In this way the dynamic behavior of SG3
could be monitored within a limited amount of time.
The SG3 field test highlighted a good match between
theory and operational condition in the gas pipe. No
negative effects were experienced in either the gas grid
or end user appliances.
An alternative to SG3 is to compress the excess gas
and feed it into a higher pressure part of the grid (e.g. 8
bar). However, this is not only expensive because of
hardware but compression also requires extra energy.
No additional hardware is required for SG3. Moreover,
the biomethane producer saves energy because the gas
can be fed into the gas grid at a pressure level below
8 bar.
3.8 Complexity and efficiency loss in
demand driven biogas systems
The addition of a flexible biogas production process
at a biogas plant increases the complexity of operation
of the facility. It also results in additional costs and
decreased capacity utilisation. Capital investment is
required in extra power rating for the CHP system, in a
gas storage system, in gas management systems, poten-
tially a new transformer and possibly a new feed in
point when the installed electric CHP-power is
increased.
Conversion of an existing biogas plant to demand
driven operation is costly and as such conversion needs
to be compensated through higher financial return.
Results from Germany (Schaubach et al, 2014) indicate
that the costs of additional flexibility of biogas plants
are sufficiently remunerated under the current frame-
work condition (EEG-legislation, revenues from EPEX
and balancing energy markets). However financial
returns may not be sufficient for conversion to demand
driven biogas if extra earnings from EPEX-Spot or
balancing markets decrease (Jacobi et al, 2014b).
3.9 Flexible bioenergy in the energy grid
The flexibility from bioenergy-plants has positive
effects for the grid and for the integration of additional
shares of variable renewable power production. For the
50Hertz-TSO-region in Eastern Germany, research
results show that a reduction of overall residual load can
be achieved by flexible bioenergy; flexible bioenergy can
be a major contributor to balancing energy (Tafarte et
al, 2014).
It can be assumed, that flexible operation of existing
bioenergy plants is an effective and cost efficient balan-
cing option compared to electricity network upgrades
and implementation of storage-alternatives (such as
pumped hydro-electric schemes). Furthermore demand
driven bioenergy plants and battery-storage can be seen
as complementary; battery-storage is focused on short-
term storage of energy whereas flexible bioenergy plants
can supply electricity on demand within a short
response time and from storage for up to 12-16 hours.
By comparison, biomethane based CHP-units can utili-
se the gas at any point of time and consequently store
energy for almost unlimited time.
Flexible bioenergy plants can be combined with
power to heat and power to gas systems. Power to heat
is currently used in Germany to avoid the shutdown of
wind based power plants; surplus electricity is used for
the provision of heat. Biogas plants can be combined
with power to heat by shutting down the CHP unit in
times of excess electricity production whilst heat
demand of the biogas plant is provided by power to
heat. This approach is not optimal from a greenhouse
gas mitigation perspective. It is the authors’ opinion
that surplus electricity from variable renewable electri-
city is better used in power to gas concepts.

Smart energy gridsPower to Gas; a means of storing surplus electricity
15
4. Power to Gas; a means of
storing surplus electricity
4.1 Electrolysis
The first step in a Power to Gas system is electrolysis
and production of hydrogen. Electrolysis is an electro-
chemical reaction, where direct electrical current (DC)
is used to split water into its constituent elements, oxy-
gen and hydrogen, according to Eq. 1.
The production of hydrogen and oxygen takes place
in an electrochemical cell, which consists of two porous
electrodes (anode and cathode), an electrolyte and a
membrane (gas barrier) which hinders the recombina-
tion of the two product gases. As seen in Equation 1,
water electrolysis is an endothermic reaction. Energy
input is required to sustain the reaction. Hydrogen is
formed via reduction at the cathode. Oxygen is formed
via oxidation at the anode. The two electrodes are elec-
trically connected via an external circuit and an ionic-
conductive electrolyte. A typical electrolyser system
comprises numerous (tens to hundreds) single cells,
electrically connected in series, forming a so called cell
stack. The performance of the electrochemical cell
depends on its total resistance. In the case of water elec-
trolysis, this resistance depends on the rate of the elec-
trode reactions and the electrical resistance caused by
the electrolyte and the external circuit. The resistance
generally increases with increasing current/power. Tem-
perature also has a large impact on the electrolysis per-
formance.
There are, in principle, three different electrolysis
technologies, which are either commercial or pre-com-
mercial. They are named after the type of the electrolyte
used. The technologies are Alkaline Electrolysis Cells
(AEC), Polymer Electrolyte Membrane (PEM) cells and
high temperature Solid Oxide Electrolysis Cells (SOEC).
The characteristics of these cells are summarized in
Table 1. Figure 9 shows a power to gas installation in
Falkenhagen, Germany.
4.1.1 Alkaline Electrolysis Cells (AEC)
The Alkaline Electrolysis Cells (AEC) technology is
the most widely used. It has been in industrial use for
decades and is also considered the most mature techno-
logy. It is generally used for small-scale applications,
with typical production rates of 10-200 Nm3 H2/h. Even
though the majority of the alkaline electrolysers operate
at a relatively low pressure (< 30 bar), systems operating
at up to 200 bar (so called high pressure systems) have
recently become commercially available. This high pres-
sure technology is expected to be particularly attractive
for large-scale applications (at MW scale) offering
advantages such as low load operation down to 5-10%,
somewhat higher efficiencies and more compact geo-
metries. However, higher operation pressure leads to
more complex safety and control systems which results
in slower dynamic response times. This makes high
pressure technology less suitable for variable power
sources such as wind and solar.
4.1.2 Polymer Electrolyte Membrane cells
Polymer Electrolyte Membrane (PEM) cell techno-
logy has the ability to operate at four times higher
power density than alkaline systems whilst simulta-
neously allowing operation at low loads (down to a few
percent of rated capacity). Thus PEM electrolysis is well
suited to variable wind and solar power (Carmo et al.,
2013). This also leads to lower operation costs. Howe-
ver, it is a significantly less mature technology than the
competing AEC technology. The installation cost is
higher due to the expensive membrane and electrode
materials. Another disadvantage of the system is that
the membrane/electrolyte needs to be exchanged every
5 to 10 years (Benjaminsson et al., 2013).
2 H2O (l)  2 H2 (g) + O2 (g) ∆Hr = 286 kJ/mole (at 25°C, 1 bar) [Eq. 1]
Figure 9: 2MW Power to gas unit based on alkaline electrolysis in Falkenha-
gen, Germany. The hydrogen is injected into the gas grid without methanation.
(Source: E.ON)

16
Smart energy grids Power to Gas; a means of storing surplus electricity
4.1.3 Solid Oxide Electrolysis Cells (SOEC)
Solid Oxide Electrolysis Cells (SOEC) is the most
promising technology, but the least mature. Similar to
PEM technology, it can be operated in the reverse
direction and produce power if desired. Due to its very
high operating temperature (700-1000°C),the efficiency
is potentially very high which should have a positive
impact on costs. Firstly, in contrast to the low
temperature technologies, a significantly larger amount
of the energy needed for electrolysis is supplied as heat
instead of more expensive electricity. Secondly, the rates
of the electrochemical reactions are significantly faster
at higher temperatures leading to an overall lower total
cell resistance which gives better cell efficiency.
Efficiencies of 90 to 95% are possible as compared to 60
to 70% for AEC and PEM technologies (Benjaminsson
et al., 2013). The high operating temperature of SOEC
enables not only production of pure hydrogen from
water but also from synthesis gas (carbon monoxide
and hydrogen) through co-electrolysis of steam and
carbon dioxide. However, SOEC operation requires
access to high-grade waste heat during start-up. This
may be sourced from a power plant or more appropria-
tely from an adiabatic catalytic reactor such as a cataly-
tic methanation process.
In addition to hydrogen, oxygen is also produced
during the electrolysis. Oxygen could be an additional
valuable byproduct from the biogas plant and used for
desulphurization by adding oxygen during the anaero-
bic digestion process or in separate desulphurization
units before biogas upgrading. By using oxygen instead
of air, nitrogen accumulation can be avoided which
otherwise makes it very hard to reach the required puri-
ties during biogas upgrading to biomethane. The oxy-
gen can also be sold to nearby industries. One such
example is a gasification plant, using direct gasification
that requires pure oxygen to produce biomethane
without nitrogen input.
Table 1. Summary of the typical characteristics of different electrolysis technologies.
AEC PEM SOEC
Type of electrolyte 20 – 30% KOH in H2O(l) Polymer, e.g. NAFION® Ceramic of yttria-stabilized
zirconia (YSZ)
Type of electrodes Ni-based Pt/C-based Ni-based (H2)
Perovskite (O2)
Type of membrane Asbestos or asbestos-free
polymer
Same as the electrolyte Same as the electrolyte
Temperature 60 – 80°C 50 – 80°C 700 – 1000°C
Pressure < 30 bars < 30 bars under evaluation
Power density ≤ 1 W/cm2 ≤ 4 W/cm2 under evaluation
Part load range 20 – 40% 0 –10% 0 –10%
Efficiency1 60 –70%, corresponding to
the power consumption
4 –5 kWh/Nm3 H2
60 –70% corresponding to
4 –5 kWh/Nm3 H2
90 –95%, corresponding to
3 –3.3 kWh/Nm3 H2
KOH=potassium hydroxide, Ni=Nickel, Pt=Platinum, C=Carbon.
1 Efficiency refers to the cell voltage efficiency based on lower heating values (LHV).
1 Nm3 H2 has a LHV of 10.79 MJ or 3 kWh; thus for example 3 kWh electricity producing 2.85 kWh of H2 yields an efficiency of 95%.

17
4.2 Power to methane
In examining the potential for power to methane the
source of carbon dioxide (CO2) is very important. The
CO2 can either be of fossil or renewable origin, extrac-
ted from the air or various industrial waste gases. Howe-
ver, capture of CO2 is not cheap and clean concentrated
sources of CO2 are not abundant. It is not simply a case
of collecting the flue gas from the stack from a power
plant and mixing it with hydrogen. The cost of CO2
capture is more expensive if the concentration of CO2
in the gas is low. Thus CO2 capture from the exhaust of
a thermal power facility with low concentration of CO2
is expensive. Estimates for the cost of CO2 range from
€ 7 – € 75 per tonne of CO2 captured, with coal plants
at the lower end and combined cycle gas turbine plants
at the upper end of this scale (Sterner (2010), IPCC
(2005)). Alternatively, the CO2 produced in other pro-
cesses, such as in an ethanol plant or at a biogas facility,
can be much cheaper. One example is the CO2 from
biogas upgrading (Ahern et al, 2015), which in most
cases is free from contaminants.
Use of the power to gas concept at a biogas facility
has great potential. When excess electricity is available,
surplus electricity may be stored through the power to
gas concept by producing hydrogen by electrolysis. The
hydrogen can thereafter be combined with CO2 to pro-
duce methane in a number of ways:
• Hydrogen is added to the anaerobic reactor and
reacted with raw biogas within the biogas dige-
ster; this is termed in-situ biological methanati-
on (Figure 10(A)). In this process it is unlikely
that a biomethane standard (> 97% methane
content) suitable for gas grid injection or for
vehicle use will be achieved. Thus a smaller bio-
gas upgrading step will be required if biometha-
ne is the proposed end product.
• Hydrogen is added to and reacted with raw bio-
gas after the biogas digester. This can be a biolo-
gical ex-situ process in a separate biological
reactor or a catalytic process (Figure 10(B)).
• Methanation may be post biogas up-grading
(Figure 10(C)). This could be employed at a site
where biogas upgrading is already in place and a
very concentrated CO2 stream is available.
A “disadvantage” of catalytic methanation is that
impurities, such as hydrogen sulphide and siloxanes,
have to be removed prior to the catalytic step. This is
not the case for biological methanation. For catalytic
methanation it may be more beneficial to perform the
methanation with raw biogas (Figure 10(B) after remo-
A H2 added in-situ to biogas
reactor to increase biogas
production; additional
upgrading step required pre-
gas grid injection
B H2 and biogas added in a
biological or catalytic
methanation unit removing
the need for traditional gas
upgrading
C H2 and clean CO2 from bio-
gas upgrading added to a
biological or catalytic
methanation unit.
Figure 10: Three different pathways using power to methane concepts at a biogas facility

18
val of hydrogen sulphide, instead of pure CO2 from the
upgrading unit (Figure 10(C)). A larger catalytic surface
will be required to handle the increased gas flow, but
less heat will be produced per volume of gas; this faci-
litates a less complicated and less costly design. A major
advantage of methanation with raw biogas is that the
costs associated with biogas upgrading can be avoided.
This is a significant cost saving and may be the only
situation that allows a sustainable financial model.
There are a number of questions to be answered
when combining a biogas plant with a power to metha-
ne application:
• For biological methanation, should hydrogen be
inserted into the digester (in-situ) as in Figure
10(A) or is it more efficient to perform this ope-
ration in an ex-situ process as in Figure 10(B)?
• If methanation is performed ex-situ, is it more
cost efficient to do this with a biological or a
catalytic method (Figure 10(B))?
• Could the biogas upgrading plant be completely
removed from the biogas plant if biological or
catalytic methanation is applied (Figure 10(B))?
• If there is an existing biogas upgrading unit,
should the CO2 from the biogas upgrading unit
be used instead of the biogas (Figure 10(C))?
None of these questions have a definitive answer
because the industry is still developing and the answer
will depend on variables including: the size of the faci-
lity; whether it is a new facility or an addition to an
existing facility; if an existing facility whether the biogas
was used in CHP or upgraded; the policy and tariffs of
the country of operation.
4.3 Catalytic Methanation
The reactions involved in generating methane from
carbon monoxide, carbon dioxide and water through
catalytic methanation are shown in Equations 2, 3 and
4 (∆Hr at 25°C). The reaction described in Equation 3 is
termed the Sabatier reaction.
The methanation reactions are thermodynamically
favored by low temperatures and high pressures. In
practice, the reactions normally take place in the pres-
ence of a nickel or a ruthenium-based catalyst normally
at 300 – 500°C, with an overall energy conversion effici-
ency of 80% (Benjaminsson et al., 2013).
The methanation reactions are highly exothermic
and generate significant quantities of heat (which could
be used for high temperature Solid Oxide Electrolysis
Cells (SOEC)). Temperature control is essential to favor
methane formation and to avoid overheating and dete-
rioration of the catalysts. There are different strategies
for temperature control: several fixed bed adiabatic
reactors with intermediate cooling (i.e. no heat is trans-
ferred to or from the reactor) or isothermal reactors (i.e.
operating at a constant temperature) with integrated
heat exchange cooling or combinations of these two.
Depending on the flow rate applied, the reactors can be
of fixed, bubbling or of circulating bed type. For metha-
nation, fixed beds are the most commonly used since
these enable the most efficient cooling (Kopyscinski,
2010). As of 2014 there are only a few companies that
develop electrolysers integrated with catalytic methana-
tion reactors. These are ETOGAS, Haldor Topsøe and
Sunfire (Benjaminsson et al., 2013: Iskov and Rasmus-
sen, 2013). These organisations are involved in the fol-
lowing projects:
• As of February 2014 ETOGAS was the only com-
pany that has sold and installed complete power
to methane systems of industrial scale; they have
installed three systems, all in Germany. The most
recent one (completed late 2013) is the world´s
largest power to gas plant. It has an estimated
average methane production capacity of 25
GWh/year and a power capacity input of 6 MWe
(suggesting a combined efficiency and capacity
factor of 48%). Their technology is based on
alkaline electrolysis and isothermal fixed bed
methanation reactors. The carbon dioxide is
sourced from an amine scrubber used for biogas
upgrading. The heat required in the amine
scrubber is supplied from the electrolysis and
methanation equipment.
• Sunfire expects that they can offer complete
power to methane systems in 2014. The first ones
will be based on alkaline electrolysis combined
with their own catalytic methanation reactor
CO (g) + 3 H2 (g) CH4 (g) + H2O (g) + heat ∆Hr = –210 kJ/mole [Eq. 2]
CO2 (g) + 4 H2 (g)  CH4 (g) + 2 H2O (g) + heat ∆Hr = –165 kJ/mole [Eq. 3]
CO (g) + H2O (g)  CO2 (g) + H2 (g) + heat ∆Hr = –41 kJ/mole [Eq. 4]

19
concept, consisting of an adiabatic reactor follo-
wed by an isothermal reactor. However, from
2016, they plan to substitute the alkaline electro-
lyser with their own SOEC-technology, which
potentially can increase the overall efficiency
(from power to methane) from 55% to 80%.
• Haldor Topsøe plans to combine their SOEC
technology with their catalytic methanation
technology. They participate in several R&D
projects using SOEC technology and a methana-
tion technology called the TREMP® process
(Topsøe Recycle Methanation Process). If star-
ting with syngas originating from bio-
mass or coal gasification, this concept is
based on three catalytic fixed bed adia-
batic reactors with intermediate coo-
ling. However, if cleaned biogas is the
starting point, the process can be sim-
plified and only two reactors are
needed.
4.4 Biological in-situ or ex-situ methanation?
4.4.1. Sequential Processes of Anaerobic Digestion
The microbiology of anaerobic digestion is complex.
It is dominated by four different trophic groups (Figure
11). It is a sequential process; the end products of one
trophic group of micro-organisms are the food source
of another trophic group of micro-organisms. This may
be noted in degradation of ethanol as highlighted by
Murphy and Thamsiriroj (2013) and Colleran (1991).
Three separate species are required. Acetogenic bacteria
(species 2) convert ethanol to acetic acid and hydrogen;
in terms of thermodynamics this is not a favourable
reaction (∆G is positive). Hydrogenotrophic methano-
genic species (species 4.1) have a high affinity for hydro-
gen (∆G is negative) and thus assist the acetogenic spe-
cies. The aceticlastic methanogenic species (species 4.2)
convert acetic acid to methane and carbon dioxide.
4.4.2 Effects of adding H2 to an anaerobic reactor
Hydrogen can be converted to methane by the
action of hydrogenotrophic methanogens; the reaction
may be represented by Equation 3. The efficiency of
biological methanation (just as catalytic methanation)
is limited to a maximum of around 80% due to the
energy released when this exothermic reaction takes
place (Benjaminsson et al., 2013). Obviously addition of
“extra” or “outside” hydrogen to an anaerobic digester
Figure 11: Four trophic groups involved in anaerobic processes (adapted from Murphy and Thamsiriroj, 2013; Colleran, 1991)
1 Acidogenic bacteria
1.1 Hydrolytic bacteria
1.2 Fermentative bacteria
2 Acetogenic bacteria
3 Homoacetogenic bacteria
4 Methanogenic archae
4.1 Hydrogenotrophic Methanogenic archae
4.2 Aceticlastic Methanogenic archae
Species 2 CH3CH2OH + H2O =CH3COO–
+ H+
+ 2H2 ∆G = 5.95 kJ/reaction [Eq. 5]
Species 4.1 2 H2 + 0.5 CO2 =0.5 CH4 + H2O ∆G = –65.45 kJ/reaction [Eq. 6]
Species 4.2 CH3COO–
+ H+
= CH4 + CO2 ∆G = –28.35 kJ/reaction [Eq. 7]
Net CH3CH2H =1.5 CH4 + 0.5 CO2 ∆G = –87.85 kJ/reaction [Eq. 8]

20
has potential to disturb the operation of the sequential
microbiological system. The problems are outlined
below:
• CO2 is very soluble; within the digester it reacts
with hydroxide ions to form bicarbonate ions
(HCO3-) which gives buffering capacity (Mur-
phy and Thamsiriroj, 2013). Introduction of H2
to a reactor consumes CO2 and creates methane.
This decreases the partial pressure of CO2, redu-
ces buffering capacity and causes an increase in
pH, which typically has a negative effect on
methanogenesis (Luo and Angelidaki, 2013a).
• Degradation of propionate and butyrate needs
very low hydrogen concentration; generally
lower than 10-4 atm (Fukuzaki et al., 1990).
Adding hydrogen to a biogas reactor may increa-
se hydrogen partial pressure, inhibiting VFA
(propionate and butyrate) degradation (Luo et
al., 2011; Siriwongrungson et al. 2007).
4.4.3 Biological methanation in the anaerobic biogas reactor
(In-Situ Reactor)
Based on Equation 3, in theory, hydrogen should in
principle be added to a biogas reactor at 4 times the
quantity of CO2. This is the theory and 100% efficiency
is not easy to obtain. If the biogas comprises 50%
CH4and 50% CO2, theoretically all CO2 will react with
H2 and the exit gas will be 100% CH4. In this simplified
analysis the quantity of CH4 produced will double. A
crucial challenge with biological conversion of H2 to
CH4 is the fact that H2 is approximately 500 times less
soluble than CO2 at 60°C. Thus the requirement to put
H2 into solution and make it available for consumption
by hydrogenotrophic methanogens is essential for an
efficient in-situ process; this may be termed a gas liquid
mass transfer criterion.
Luo et al. (2011) reported improved gas liquid mass
transfer of the process through very high levels of
mixing. However, up-scaling of such a system may
result in very high parasitic energy demands and lower
life cycle energy efficiencies. Insertion of H2 by a cera-
mic diffuser with pores of 14 – 40 micron (Luo and
Angelidaki, 2013a) or a hollow fibre membrane (HFM)
with diameter of 284 microns (Luo and Angelidaki,
2013b) were also trialed and showed improvements in
efficiency as exemplified by higher methane content and
lower CO2 and H2 contents in the biogas. It is difficult
to achieve maximum efficiency in an in- situ reactor;
the methane content increases but H2 and CO2 are still
present to varying degrees in the exit gas.
MicrobEnergy evaluated an in-situ methanation
process in a pilot plant based on a conventional hori-
zontal digester with high dry matter content. The high
viscosity is important since it decreases the rising speed
of the hydrogen bubbles that are added at the bottom of
the digester. Thus far, the methane concentration has
successfully been increased from 50 to 75% (Benjamins-
son et al. 2013).
4.4.4 Biological methanation in a separate reactor
(Ex-Situ Reactor)
In-situ biogas upgrading suffers from many techni-
cal challenges that can be avoided by using an external
bioreactor optimized for the process. Luo and Angelida-
ki, (2013b) investigated an application of biological
methanation to biogas upgrading in an ex-situ vessel
enriched with hydrogenotrophic methanogens. They
achieved very high consumption of H2 and CO2. Enri-
ched thermophilic inoculum performed 60% better
than enriched mesophilic inoculum. It is suggested
(Luo and Angelidaki, 2013b) that the upgrading reactor
volume is of the order of 11% of the original biogas
reactor. It is possible to achieve gas grid injection speci-
fication from ex-situ biomethanation (Luo and Angeli-
daki, 2012).
An alternative to a stirred tank reactor is a trickle
bed reactor. An advantage of this technique is that the
energy required for stirring is avoided. In a recent study
(Burkhart et. al. 2014) it was shown that a trickle bed
reactor can operate without gas circulation, due to the
formation of a three-phase system on the carrier sur-
face. Burkhart and co-workers (2014) have achieved
methane concentrations higher than 98%. Another
technology investigated to avoid or decrease the energy
consumption needed for stirring involves use of hollow
fibre membranes to dissolve gas into the liquid phase
(Benjaminsson et al., 2013).
MicrobEnergy, Krajete and Electrochaea are compa-
nies in start-up phase in the field of biological methana-
tion. They all have pilot plants in operation. Krajete and
Electrochaea focus only on biological methanation in a
separate ex-situ reactor while MicrobEnergy also stu-
dies in-situ systems (Benjaminsson et al. 2013). The
ex-situ reactor for biological methanation is in most

21
cases designed with hydrogen addition in the bottom of
the continuously stirred tank reactor operated at 65°C
(Benjaminsson et al., 2013). The stirring speed is very
important in this type of system. A high stirring speed
increases the hydrogen solubility and increases the
methane yield but also the energy consumption.
Fraunhofer IWES, together with partners ZSW and
Solarfuel are conducting an on-going evaluation of an
ex-situ methanation process for biogas plants with a
raw gas capacity of up to 50 m3/h. The study is located
on the premises of the Hessian biogas research centre
(Persson and Baxter, 2015).
In December 2013, Electrochaea was awarded a sub-
stantial grant to design, engineer, build, and operate a
1MW power to gas facility near Copenhagen in Den-
mark in a project called BioCat. A 1 MW alkaline elec-
trolysis plant from Hydrogenics was scheduled to be
installed and surplus electricity used to produce hydro-
gen. The hydrogen will be combined with raw biogas or
CO2 from a biogas upgrading plant and fed into an ex-
situ biological methanation reactor. The produced
methane will be injected into a nearby gas distribution
system. Start-up is planned for July 2015.
4.5 Can biogas upgrading be replaced by
methanation ?
Obviously the time over which electricity may be
deemed surplus and used to produce hydrogen is finite
and uncertain. Hydrogen produced from surplus elec-
tricity (which would be lost to the system without con-
version to hydrogen) should in principle be significant-
ly cheaper than hydrogen produced from electricity that
is produced at a time where there is demand for electri-
city. Storage of hydrogen is also a significant cost consi-
deration; an alternative would be to store biogas and
react with hydrogen when it is available.
If the aim of the biogas plant is to produce bio-
methane over the entire year, the economics may be
such that biogas upgrading at a specific biogas facility
could be employed for both biological methanation
through hydrogen upgrading (when electricity is sur-
plus and hydrogen is cheaper), and a traditional biogas
upgrading system when electricity supply is not surplus
and hydrogen is more expensive. Thus one large advan-
tage of biological methanation, savings in investment
and operational costs for a traditional biogas upgrading
system, may not be fully realizable. It is also yet to be
proven which methanation systems are able to reach the
level of specification of a traditional biogas up-grading
system and again this may necessitate co-location of
biological methanation and traditional biogas upgra-
ding. A significant opportunity would be lost if the
power to methane system does not replace (to some
extent) the energy and cost of a traditional biogas up-
grading system. However another option may be to
produce biomethane when hydrogen is cheap due to
low demand for electricity and produce electricity in a
CHP system at times of high demand for electricity
(Figure 12).
Figure 12: Co-location of CHP and biological methanation (from Ahern et al., 2015)
A Gas grid injection after
biological methanation at
times of low power
demand
B CHP production at times
of peak power demand

22
Smart energy grids Discussion
Another solution may be to separate the concept of
surplus renewable electricity storage from biological
methanation. This may be exemplified by locating a
wind park and biogas facility adjacent to one another
(Figure 13) and by converting some of the electricity
from the wind turbine to H2 and use it purely as part of
a gas upgrading system. Biogas may be stored until suf-
ficient hydrogen is available for the biomethanation
system.
5.Discussion
The perspective of IEA Bioenergy Task 37 is that
biogas could and should have an important role in futu-
re smart energy grids for balancing increased amounts
of variable renewable electricity generation. This may
be achieved in two ways:
• Through use of demand driven electricity pro-
duction from biogas plants in times of maxi-
mum demand for electricity and low supply; for
example when there is little wind and wind tur-
bines are not producing sufficient electricity.
• Through power to methane when the demand
for electricity is less than supply of electricity.
This has a serendipitous benefit of upgrading
biogas to biomethane through use of CO2 in the
biogas.
Figure 13: Biogas plant with adjacent wind park

Smart energy gridsDiscussion
23
Regulation of the electricity grid tends to be a func-
tion of National Government with Grid Operators
generally responsible for implementation.Without clear
framework conditions and endorsement from Govern-
ment there is a risk that different market actors will
regard each other, rather than themselves, as the ones to
take the first step. The main actors include the power
generators, grid owners and third parties involved in
trade. Development of power to gas requires economic
incentives, such as state subsidies, grants or electricity
feed-in tariff regulated by the generation and consump-
tion of electricity with higher feed-in tariffs when elec-
tricity is needed and vice versa.
Utilisation of smart grids and interconnection of the
gas and electricity grids through the power to gas con-
cepts provide a means of storing renewable electricity
that would otherwise be lost to the system. The life
cycle efficiency from electricity to methane is in the
range of 48 to 76% taking the efficiency of electrolysis
to be between 60 and 95% and methanation of around
80%. If power to methane to power is employed, net
conversion efficiency in the range 19 to 45% would be
expected; this assumes electrical efficiency between 40%
(at small scale) and 60% (at large Combined Cycle Gas
Turbine (CCGT) scale). One situation that should be
avoided is generation of electricity from methane at the
same time that surplus electricity is used to produce
methane, in which case the overall effect is just a loss of
electricity (Ahern et al., 2015). While close integration
of electricity grids between countries should be able to
minimise inefficiencies, power to gas is likely to be nee-
ded for grid balancing at the regional level and where
insufficient interconnection is available.
Power to gas must be compared to alternatives as a
means of energy storage. Pumped hydro-electricity
schemes have life cycle efficiencies in the range 75 –
80%, however the potential for new sites are limited and
the large scale of these systems means very long lead
times for construction (Ahern et al., 2015). An added
benefit and a differentiation between power to gas and
other energy storage schemes is that power to gas chan-
ges the energy vector to gas. When it is considered that
typically electricity is approximately 20% of final energy
demand whilst transport and thermal energy tend to be
of the order of 40% each (Murphy and Thamsiriroj,
2011), the benefit of changing the energy vector may be
noted. This is highlighted by the weighting attributed to
renewable energy supply in transport (RES-T) attribut-
ed to renewable gaseous fuel produced from non-biolo-
gical origin in the proposed amendment to the EU
Renewable Energy Directive (European Commission,
2014). The weighting of 2 to the energy content of the
fuel is transferrable to extra green certificates in the
biofuel obligation certificate scheme, which is for
example the case in Ireland. This weighting makes bio-
fuel production for transport financially viable in Ire-
land (Ahern et al., 2015). Thus it may be suggested that
an optimal route for power to gas is to make renewable
transport fuel for natural gas vehicles from surplus elec-
tricity.
The authors expect that many power-to-gas facilities
that utilize CO2 from biogas plants will be on the mar-
ket within 5–10 years, especially in countries with
numerous biogas facilities and large capacities for gene-
ration of variable renewable electricity, such as Germa-
ny, Denmark and The Netherlands. Biological methana-
tion plants will probably be more competitive in smaller
installations, while catalytic methanation may be more
competitive in larger installations.
One uncertainty for the power to gas industry is
whether there will be successful development of other
methods and applications which use surplus electricity.
This may increase the competition for, and the price of,
surplus electricity. It may emerge that hydrogen could
have a better economic return outside the energy sector.
It should also be considered what will happen when the
capacity of the electrical power system is in excess of
electricity demand. Who will build new power plants? If
there is no excess electricity production there may be
little demand for power to gas facilities. It is reasonable
to expect that the electricity grid owners will feel their
major task is to invest in the electricity grid, rather than
investing in capacity to dispatch electricity. Potentially
there is scope for biogas facilities to invest in wind tur-
bines and power to gas systems as a biogas upgrading
system.

24
Smart energy grids Conclusions and recommendations
6. Conclusions and
recommendations
The annual growth of variable renewable electricity
is increasing and is projected to continue to increase in
the period to 2050. Challenges associated with the inter-
mittent character of wind, ocean and solar power will
become more problematic. Today, there is little agree-
ment on how variable renewable electricity will be
balanced in the future and what developments will take
place in the next 5–10 years. Islands such as Ireland are
looking at electrical interconnectivity with France and
the UK. A potential challenge for interconnectivity is
that electricity will be purchased at a higher price than
its cost of generation. Electrical interconnectivity may
thus be expensive for a country. The gas grid may be
seen as an alternative to electrical connection particu-
larly for island grids. Policy is required at Government
level to indicate the preferred route. It can be strongly
argued that future feed-in tariff schemes should be desi-
gned to increase the support for producers that contri-
bute to balancing the electricity grid and generate elec-
tricity when it is needed and/or store it when there is a
surplus. This will create financial incentives for biogas
plants to develop and build systems to achieve this tar-
get through demand driven biogas production and
power to methane systems.
Biogas plants are more complex when less biode-
gradable substrates are used. Methanation as well as
demand driven biogas production will further add to
this complexity. There will be a need to increase system
integration within the biogas plant; it might not be
necessary to optimize every single unit operation, but
instead the energy consumption and operational cost of
the entire plant should be optimized. Within a Smart
Energy Grid system the optimization may not be in the
biogas facility itself, but the role it will play in a broader
energy supply market.
Through this publication IEA Bioenergy Task 37
highlights the potential role of biogas in future smart
energy grids. As of 2014 power to gas and demand dri-
ven biogas plants are developing technologies; there is
no definitive optimal solution or technical layout
recommended. IEA Bioenergy Task 37 will continue to
produce publications to describe the development and
future implementation within this field.

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25
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Smart energy gridsRemoval of methane from the off-gas
27
IEA BIOENERGY Task 37– Energy from Biogas
IEA Bioenergy aims to accelerate the use of environmentally sustainable and cost competitive bioenergy
that will contribute to future low-carbon energy demands. This report is the result of work carried out by
IEA Bioenergy Task 37: Energy from Biogas.
The following countries are members of Task 37, in the 2013-2015 Work Programme:
Austria Bernhard DROSG bernhard.drosg@boku.ac.at
Günther BOCHMANN guenther.bochmann@boku.ac.at
Australia* Bernadette McCABE bernadette.McCabe@usq.edu.au
Brazil Cícero JAYME BLEY cbley@itaipu.gov.br
Denmark Teodorita AL SEADI teodorita.alseadi@biosantech.com
European Commission: Task Leader David BAXTER david.baxter@ec.europa.eu
Finland Jukka RINTALA jukka.rintala@tut.fi
France Olivier THÉOBALD olivier.theobald@ademe.fr
Guillaume BASTIDE guillaume.bastide@ademe.fr
Germany Bernd LINKE blinke@atb-potsdam.de
Norway Roald SØRHEIM roald.sorheim@bioforsk.no
Republic of Ireland Jerry MURPHY jerry.murphy@ucc.ie
Republic of Korea Ho KANG hokang@cnu.ac.kr
Sweden Tobias PERSSON tobias.persson@energiforsk.se
Mattias Svensson mattias.svensson@energiforsk.se
Switzerland Nathalie BACHMANN enbachmann@gmail.com
The Netherlands Mathieu DUMONT mathieu.dumont@RvO.nl
UK Clare LUKEHURST clare.lukehurst@green-ways.eclipse.co.uk
Charles BANKS cjb@soton.ac.uk
* Australia joined Task 37 in 2015
Published by IEA Bioenergy, December 2014 http://www.iea-biogas.net
IMPRESSUM: Graphic Design by Susanne AUER
ISBN 978-1-910154-13-7 (eBook electronic edition)
WRITTEN BY

Tobias Persson
Anna-Karin Jannasch
Energiforsk
Nordenskiöldsgatan 6
211 19 Malmö
Sweden
Jerry D Murphy (corresponding author)
Eoin Ahern
Science Foundation Ireland (SFI)
Marine Renewable Energy Ireland (MaREI)
University College Cork
Cork
Ireland
Jan Liebetrau
Marcus Trommler
DBFZ – Deutsches Biomasseforsch-
ungszentrum gemeinnützige GmbH
Torgauer Straße 116
04347 Leipzig
Germany
Jeferson Toyama
Itaipu Binacional
Foz do Iguaçu
Brazil
EDITED BY:
David Baxter
European Commission
JRC Institute for Energy
and Transport
1755 LE Petten
The Netherlands

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