Renewable Energy 78 (2015) 648e656
Contents lists available at ScienceDirect
Renewable Energy
journal homepage: www.elsevier.com/locate/renene
A perspective on the potential role of renewable gas in a smart energy
island system
Gallacho
ir a, c,
Eoin P. Ahern a, b, c, Paul Deane a, c, Tobias Persson d, Brian O
Jerry D. Murphy a, b, c, *
a
Environmental Research Institute, University College Cork, Ireland
Science Foundation Ireland (SFI), Marine Renewable Energy Ireland (MaREI) Centre, Ireland
School of Engineering, University College Cork, Ireland
d
Energiforsk AB e Swedish Energy Research Centre, Sweden
b
c
a r t i c l e i n f o
a b s t r a c t
Article history:
Received 22 August 2014
Accepted 21 January 2015
Available online 11 February 2015
This paper examines the potential role for Power to Gas (P2G) as applied to an island energy system with
high levels of renewable electricity penetration. P2G systems require both a supply of green electricity
and a source of CO2. Cheap electricity is essential for a financially sustainable P2G system. Using a PLEXOS
model it was determined that deploying 50 MWe of P2G capacity on the 2030 Irish electrical grid may
reduce absolute levels of curtailed wind by 5% compared to the base case. CO2 capture is expensive. The
cheapest method of sourcing CO2 for a P2G system is to employ a methanation process whereby biogas
from anaerobic digestion is mixed with hydrogen from surplus electricity. Anaerobic digestion in Ireland
has a potential to produce biomethane to a level of 10.2% of energy in transport (19.2 PJ/a). The potential
CO2 resource from anaerobic digestion could allow for a further 8.9% of energy in transport (16.6 PJ/a)
from P2G production. An optimal model is proposed including for co-location of a biogas system with a
P2G system. The model includes for demand-driven biogas concepts allowing electrical grid balancing
and the supply of gaseous transportation fuel. Biofuel obligation certificates allows for a financially viable
industry.
© 2015 Elsevier Ltd. All rights reserved.
Keywords:
Biogas
Carbon capture
Electricity storage
Transport biofuel
Power to Gas
Demand driven biogas
1. Introduction
1.1. The challenge of increasing levels of renewable electricity
1.1.1. Renewable electricity capacity as a proportion of demand
For many countries, particularly those in Western Europe, wind
is expected to play a very significant role in meeting their renewable electricity targets. Fig. 1 shows expected installed wind capacity as a proportion of minimum demand in summer 2020. Even
with interconnection, Ireland and Spain will, at times, have in
excess of 100% of demand available from wind, meaning curtailment will be required. Looking to 2030 and beyond, renewables
will play an increasingly large role in energy systems globally,
creating serious technical challenges.
* Corresponding author. Environmental Research Institute, University College
Cork, Ireland.
E-mail address: [email protected] (J.D. Murphy).
http://dx.doi.org/10.1016/j.renene.2015.01.048
0960-1481/© 2015 Elsevier Ltd. All rights reserved.
Ireland is located on the Atlantic coast of Europe and presents a
very interesting case study, as it is an island grid with very high
levels of wind penetration. The Republic of Ireland, in 2030 is expected to have approximately 6800 MWe of installed variable
renewable capacity (dominated by wind) representing approximately 50% of installed capacity.
1.1.2. Dispatch and curtailment
In 2012, the total wind energy generated on the island of Ireland
was 18.51 PJ. Dispatch-down of wind energy was 0.40 PJ, representing 2.1% of total available wind energy [2]. The main factors
which determine the level of curtailment are the amount of
installed wind capacity and the instantaneous limit for system nonsynchronous penetration (SNSP) allowed on the grid [3]. SNSP is
defined as
wind generation þ HVDC imports
:
system demand þ HVDC exports
all units in MWe.
(1)
E.P. Ahern et al. / Renewable Energy 78 (2015) 648e656
649
1.2.3. Electric vehicles
Electric vehicles (EVs) have the potential to play a significant
role in demand side management, with smart charging and overnight charging. Ireland has an ambitious target to have 10% of the
road transport fleet powered by electricity by 2020, equating to
roughly 190,000 private cars [8]. However, since 2010, fewer than
500 EVs have been registered in the country (excluding hybrids)
[9]. Realistically, EVs are not expected to have a significant impact
on the grid until post 2030.
1.3. Power to Gas
Fig. 1. Wind capacity as proportion of minimum demand in summer 2020 (including
for interconnection) [Based on data from Ref. [1]].
Generally, for a given installed capacity of wind, the higher the
SNSP limit, the lower the level of curtailment [3]. In other words, if
a higher proportion of the system demand can be served by wind,
less of the available wind generation will need to be curtailed. By
2020, a SNSP limit of 60e75% should be technically achievable [4],
based on frequency response and transient stability requirements.
McGarrigle et al. [3] carried out a study to estimate the required
installed wind capacities which would allow the island of Ireland to
reach their 2020 renewable energy sources in electricity (RES-E)
targets, which included an estimate of curtailed wind energy. A
minimum curtailment level of 6.5% was observed, regardless of
what the SNSP limit was set at. In scenarios where more offshore
wind was included, curtailment decreased, mainly due to the wider
geographical spread. In the most likely scenario, with a “medium”
installed offshore wind capacity, McGarrigle et al. [3] estimated
overall all island curtailment at 14% for a SNSP limit of 60%, dropping to 7% for a SNSP limit of 75%.
1.2. Approaches to minimise wind curtailment
1.2.1. Pumped hydro electricity storage
Pumped hydro electricity storage (PHES) is the most mature
large-scale energy storage option, with the ability to store energy
for periods of hours up to days. At times when surplus electricity is
available, water is pumped from a low reservoir to a high reservoir.
When electricity demand is high, water is allowed flow back down
to the low reservoir, passing through a turbine at the exit to the
lower reservoir. The round trip efficiency of PHES is typically
75e80%. Globally, there are over 300 PHES facilities in operation,
with a total installed capacity in excess of 95 GWe [5]. However, the
potential for new sites in many countries, such as Ireland, is limited
by the required topography, geotechnical conditions, and the time
scale involved in such major pieces of infrastructure.
1.2.2. Compressed air energy storage
Compressed air energy storage (CAES) systems use electricity to
pump air into underground storage sites at high pressure, usually
between 4 and 8 MPa [6]. At times of peak electricity demand, the
compressed air is released and enters the combustor of a natural
gas turbine power plant. The underground storage site is generally
an existing rock cavern, depleted gas field, salt dome or disused
mine. The efficiency of CAES systems typically ranges from 60 to
80%. A 268 MWe facility is planned for a salt deposit at Larne,
Northern Ireland with a target commissioning date of 2017 [7].
Power to Gas (P2G) is a relatively new concept which involves
two stages. The first stage converts electrical power to hydrogen via
electrolysis. The second stage converts hydrogen to methane either
catalytically or biologically through reaction with CO2. An efficient
P2G process requires cheap electricity (such as that which would
otherwise have been curtailed), a cheap source of CO2 and an
efficient gas distribution system (such as the natural gas grid). A
number of facilities are already producing methane from electricity
and injecting it to the gas grid, such as the 6 MWe Audi e-gas plant
at Werlte [10].
1.3.1. Electrolysis
Three main technologies are available for electrolysis; alkaline
electrolysis, polymer electrolyte membrane (PEM) electrolysis and
high temperature solid oxide electrolysis cells (SOEC). Typical efficiencies for alkaline and PEM electrolysis lie in the range of
50e70%. Far higher efficiencies may be possible using SOEC technology. SOEC systems operate at high temperature (700e1000 C),
allowing for efficiencies of 90e95%. However, this technology is at
an early stage of development. A significantly larger proportion of
the input energy is required as heat than for alternative electrolysis
techniques. This could mean lower running costs if a source of highgrade heat is readily available, such as from a catalytic methanation
process.
1.3.2. Methanation
Methanation may be catalytic or biological. The catalytic
methanation process is described by the Sabatier reaction, whereby
carbon dioxide and hydrogen combine exothermically to give
methane, water and heat (Equation (2)).
4H2 þ CO2 ¼ CH4 þ 2H2 O
DHR ¼ 165 kJ=mol
(2)
The catalytic (Sabatier) process is well understood and has been
used for many years in various applications, most notably for the
removal of trace amounts of CO2 in ammonia production. The
process typically takes place at around 300 C, and at pressures of
50e200 bar. A catalyst is required to reduce the activation energy of
the reaction and allow it to proceed at suitable rates. Such catalysts
are typically nickel-based, on an alumina carrier [11].
Biological methanation is carried out by hydrogenotrophic
methanogens, a group of microorganisms which consume
hydrogen and carbon dioxide to produce methane. These are
strictly anaerobic microbes of the archaea domain, and are present
in anaerobic digesters. These methanogens generally grow at
35e70 C [12]. The free energy associated with the biological
reduction of CO2 to CH4 using H2 is 131 kJ/mol [13], indicating that
the reaction is favourable. The process may be carried out “in-situ”
by simply injecting hydrogen into an anaerobic digester. Alternatively it may be carried out “ex-situ” in a separate vessel.
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1.3.3. Efficiency of Power to Gas process
The efficiency of the overall P2G process depends on both the
electrolysis and the methanation steps. The methanation process is
thermodynamically limited to about 80%; therefore an overall efficiency in the region of 55e80% may be expected. This is of similar
efficiency to PHES and CAES. The P2G process changes the energy
vector from electricity to gas. This is very relevant for renewable
energy in transport.
1.4. The challenge of increasing levels of renewable energy in
transport
The Renewable Energy Directive (2009/28/EC) has set a target
share for the EU and for each Member State of renewable energy
sources in transport (RES-T) of at least 10% by 2020. In June 2014, EU
energy ministers agreed to limit the share of biofuels from cereal
and other starch rich crops, sugar and oil crops to 7% [14]. This
poses a very difficult challenge to the transport fuel sector due to
the unavailability of sufficient commercially available second (or
third) generation biofuel systems to deliver 3% of energy in transport within the EU. In 2012 a proposal for a Directive of the European Parliament and of the Council suggests that in calculating the
contribution to the RES-T target, renewable gaseous fuels from nonbiological origin (P2G) shall be considered at 2 times their energy
content for the purposes of meeting the 2020 target [14].
1.5. Aims and objectives of paper
The ambition of this paper is to highlight the role that renewable
gas coupled with P2G technologies can play in Smart Energy systems. Renewable gas can facilitate intermittent variable renewable
electricity supply in an island grid whilst producing a third generation renewable transport fuel.
The specific objectives of this paper are to:
Assess the likely resource of renewable electricity that would be
available at sustainable cost to produce hydrogen.
Assess the likely source and resource of CO2 that would be
available at sustainable cost to produce methane in reaction
with hydrogen.
Evaluate an optimal model for P2G systems.
Assess the potential resource of renewable gas in Ireland for use
as a renewable transport fuel.
Assess the financial sustainability of such a technology.
2. Methodology
2.1. Likely resource of curtailed renewable electricity
A sustainable Power to Gas system is predicated on use of
renewable electricity which would otherwise be curtailed. P2G
systems will need to be thought of as integral parts of the overall
energy system, rather than isolated systems. The interaction between a P2G system and an integrated gas and electricity system
was examined for the All-Island network using a 2030 model of the
Northwest European Power system developed in the PLEXOS Integrated Energy software.
PLEXOS is a modelling tool used for electricity and gas market
modelling and planning. The PLEXOS modelling tool is used by the
Commission for Energy Regulation (CER) in Ireland to validate
Ireland's electricity market and has a history of use in academic
research [3,15]. The gas and the electricity model in PLEXOS are
integrated and the energy system is optimised using mixed integer
linear programming that aims to minimize an objective function
subject to the expected cost of electricity dispatch and a number of
constraints including gas delivery. The model provides the capability to model the costs and constraints of gas delivery from its
source fields via gas interconnectors, through storage and on to
meet demand including those in the power generation sector.
Within the electricity sector, the model optimises thermal and
renewable generation, pumped storage, as well as reserve classes
subject to operational and technical constraints. The objective
function of the model includes operational costs, consisting of fuel
costs and carbon costs; start-up costs consisting of a fuel offtake at
start-up of a unit and a fixed unit start-up cost. Penalty costs for
unserved energy and a penalty cost for not meeting reserve requirements are also included in the objective function.
This model allows the P2G Plant to compete with other existing
technologies for variable renewable electricity integration such as
storage and interconnection. System level constraints consist of an
energy balance equation ensuring supply meets regional demand
at each period. Constraints on unit operation of power plant include
minimum and maximum generation, maximum and minimum up
and down time and ramp up and down rates. Within the model the
P2G process is included as a purchaser of energy from the electricity market. A similar purchaser approach was used to model
charging electric vehicles as described in Calnan et al. [15].
2.2. Likely resource of CO2
The CO2 required for the methanation process may be acquired
from a variety of different sources. These include ambient air,
thermal power plant flue gases and biogas produced by anaerobic
digestion. Due to the nature of the catalysts, a gas stream free from
contaminants (such as H2S, halogens, ammonia, tars and particles)
is required. Nitrogen is an inert gas and is not a contaminant to a
catalytic process. However, low concentrations of CO2 necessitate
more catalyst to compensate for higher gas flows. For this reason, it
might be economical beneficial to aim for streams with high CO2
concentrations. The paper investigates the cost of full carbon capture per unit of renewable gas produced. This will be an upper limit
on the cost of sourcing CO2 for P2G.
2.3. Optimal model for P2G systems
There are numerous potential configurations of P2G systems.
These depend on the source of CO2; the overall composition of the
gas which contains the CO2; and whether a catalytic or biological
methanation process is employed. There are obvious connections
between P2G and biogas systems, not only that both technologies
produce renewable gas but that biogas is a source of uncontaminated concentrated CO2. The paper will analyse the optimal integration of biogas and P2G systems.
2.4. Potential resource of renewable gas in Ireland
The biogas potential from agricultural slurries, slaughter waste,
grass and the organic fraction of municipal solid waste (OFMSW)
has been previously estimated for a 2020 scenario [16,17]. By
looking at the biogas production and typical percentage methane
from each source, an estimate of total available CO2 to P2G systems
may be produced. Four main substrates are considered: agricultural
slurries; slaughter wastes; the organic fraction of municipal solid
waste (OFMSW) and surplus grass.
The agricultural slurries considered in this analysis were those
from cattle, pigs, sheep and poultry. Due to the difficulty of
collecting these slurries, only 5% of cattle, sheep and pig slurry
and 75% of chicken slurry were included in the practical
resource.
E.P. Ahern et al. / Renewable Energy 78 (2015) 648e656
Each year in Ireland, about 12 million poultry and 8 million
livestock (including sheep, cattle and pigs) are slaughtered for
food production [16]. The Animal By-products Regulations state
that intestinal content, stomach, rumen, blood and low-risk
animal waste may be digested and the digestate, applied to
non-pasture land.
OFMSW refers only to food and garden waste which will
degrade biologically. The OFMSW production rate was estimated from population projections from the Central Statistics
Office (CSO). The practical potential for 2020 was taken as 25% of
the total potential.
Grass is the most abundant available feedstock for anaerobic
digestion in Ireland. Approximately 92% of agricultural land in
Ireland is under grass, or roughly 4.19 Mha. Wall et al. [17]
produced revised estimates of the biomethane potential from
surplus grass land based on the work by McEniry et al. [18]
assuming 10% of the potential resource was to be used in
anaerobic digestion.
2.5. Costs of P2G systems
The costs of P2G systems depend on a number of inputs. The
cost of hydrogen depends on the cost of electricity and the capital
and operating cost of the electrolysis system. The cost of electricity
is associated with the level of likely curtailment and the quantity
required. The PLEXOS model described in Section 2.1 will allow a
likely evaluation of this cost. The literature will allow a costing of
electrolysis systems. Combining these costs will allow a cost of
H2 production. Carbon is not free and its capture must be costed.
This will be carried out using a literature review. Methanation is not
a mature technology. There are at most a handful of demonstration
type systems in place in 2014. There are a wide range of costs. This
cost will be the least well defined.
3. Results and discussion
3.1. Potential resource of curtailed electricity
Two scenarios are considered in the PLEXOS model, a base case
with no P2G process and a second including P2G. In the base case,
there were 3590 h of wind curtailment. For 3165 of these hours,
curtailment exceeded 50 MWe, therefore this capacity was selected
as a reasonable upper limit for the P2G system. The model has no
spatial awareness, so this 50 MWe may be at a single location or
distributed.
651
In the model, the P2G facility bids for electricity at V50/MWeh,
although the actual market price paid may quite often exceed this.
At this bid price, the plant runs approximately 4100 h of the year,
with the average price paid for electricity around V58/MWeh. Fig. 2
shows the relationship between the price of electricity and the
operating hours of a P2G system for a typical week in winter 2030.
As might be expected, the P2G system consumes electricity at full
rated capacity when the cost of electricity is low. As the market
price of electricity increases, the P2G system stops drawing load.
Including a 50 MWe P2G system reduced the annual curtailed
renewable energy from 11.75% in the base case to 11.43%. This
equates to 0.27 PJ of electricity per annum. Assuming a conversion
efficiency of 60%, this could give 0.16 PJ of renewable gas.
Fig. 3 compares curtailment levels for the base case and the
50 MWe P2G scenario over the same period as Fig. 2. It can clearly
be seen that the peak curtailment levels for the system with
50 MWe P2G are reduced in comparison to the base case. Taking a
typical cost of wind energy production of V50/MWh, the reduction
in curtailment could result in an avoided cost of V3.7 million/a for
wind farm operators.
A sensitivity analysis was conducted where the bid price was
increased from V50 to V100/MWeh. The results are summarised in
Table 1.
It's interesting to note that while 0.73 PJ of electricity was
consumed by the system at the V50/MWh bid price, the level of
curtailed wind energy was only reduced by 0.27 PJ. This is due to
the fact that periods with cheap electricity prices do not always
correlate with high wind generation. Increasing the bid price to
V100/MWh allowed the P2G to operate at a capacity factor of 99%
over the year. With the plant running almost continuously, 1.57 PJ
was consumed, leading to a reduction in curtailed energy of
0.45 PJ. So while the increased utilisation of the plant was beneficial to the overall curtailment level, a lower proportion of the
total energy consumed could be attributed to otherwise curtailed
wind energy.
A continuous system may not then be the best approach, due
to the fact that the wind resource will not be available continuously. It may make more sense from a grid perspective to instead
deploy a larger P2G system, but one which only operates at, say, a
50% capacity factor. From a plant operator's perspective, cheaper
electricity means cheaper product gas, so a plant running at lower
capacity may make more economic sense. Capital costs for
methanation systems are still very uncertain, however the savings
achieved by operating a small plant at a high capacity factor
would need to be assessed against the higher electricity costs
incurred.
Fig. 2. Market price of electricity and operating periods for 50 MWe P2G.
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E.P. Ahern et al. / Renewable Energy 78 (2015) 648e656
Fig. 3. Typical curtailment levels for electrical grid with and without 50 MWe P2G capacity.
3.2. Sources of CO2 for catalytic methanation systems
3.2.1. CO2 from ambient air
The CO2 concentration in ambient air is approximately
400 parts per million (ppm), or 0.04% by volume. Thus, a free,
almost limitless but very dilute CO2 stream is readily available for
use in Power to Gas systems. The majority of the processes reported
in the literature use NaOH chemical absorption processes [19].
However, capturing this CO2 is quite energy intensive due to the
low concentration levels and the large amounts of heat required to
reverse the absorption reaction and release the CO2. This has been
estimated at 17.6 GJ per tonne of CO2 captured. If this CO2 was used
in a methanation reactor, the energy required to capture the CO2
would represent 92% of the thermal energy contained in the
resultant CH4 [19]. A far more efficient NaOH scrubbing system has
been developed by ZSW in Germany [20], which claims to require
8.2 GJ of electricity per tonne of CO2 captured (43% of stored thermal energy of CH4 produced). However, the integration of such a
system with a P2G system may allow the heat from the methanation reaction to be used in the NaOH scrubbing step, increasing
overall process efficiency. House et al. [19] predict that carbon
capture from air will cost in the region of $1000/t CO2 (V735/t CO2),
while other carbon mitigation technologies may be possible for
closer to $300/t (V220/t). Each tonne of CO2 captured can produce
504 m3n of CH4 (See Box 1). The cost of carbon capture from air is
therefore approximately V1.46 per m3n of CH4 subsequently produced in a methanation process. This is significantly higher than
the retail cost of compressed natural gas in a service station
(approximately V1 per m3n). This is at present excluded as a
resource of CO2.
Box 1
Conversion of CO2 to CH4.
4H2 þ CO2/CH4 þ 2H2O
Molar mass CO2: 44 g/mol
Molar mass CH4: 16 g/mol
44 tonnes CO2 / 16 tonnes CH4
1 tonne CO2 / 0.36 tonnes CH4
Density CH4: 0.714 kg/m3n
¼>1 tonne CO2 / 504 mn3 CH4
3.2.2. CO2 from thermal plants
Carbon capture systems for thermal power plants produce a
relatively concentrated stream of CO2 which may be stored or
sequestered, rather than emitted to the atmosphere. The CO2
concentration in flue gases is usually in the range of 3e15% by
volume. A liquid solvent, such as monoethanolamine (MEA), is
typically used in an absorption process to capture the carbon dioxide in the flue gases. A large volume of gas must be handled in
order to capture the relatively small amounts of CO2 contained in it.
The cost associated with carbon capture from power plants is
very high. A report published in 2012 by the Society of Petroleum
Engineers concluded that carbon capture and storage (CCS) for coal
or gas power plants will not become economical within the next 20
years [21]. The capital cost of a carbon capture system on a newbuild power plant could be as high as 100% of the cost of the
basic plant [22]. The cost of a retrofit system could be higher still;
one estimate suggests capital costs could be 15e20% higher than for
plants originally designed for CCS [23]. Estimates for the cost of
carbon capture range from V7 to V75 per tonne of CO2 captured,
with coal plants at the lower end and CCGT plants at the upper end
of this scale [19] [22], [23]. This would work out at V0.02e0.18 per
m3n of CH4 subsequently produced in a methanation process.
In 2011, there were 27 thermal power plants in operation in the
Republic of Ireland, with a total generation capacity of 5956 MWe
[24]. A total of 12.14 Mt of CO2 was emitted in that year. Applying a
90% recovery factor (as expected for carbon capture from flue gases)
gives a practical resource of 208 PJ/a. This would correspond to
110% of expected energy in transport in 2020.
3.2.3. CO2 from anaerobic digestion
Anaerobic digestion is a microbial process whereby organic raw
materials are broken down in to a biogas in an oxygen-free environment. The main components of the resulting biogas are
methane (50e70%) and carbon dioxide (30e50%), along with small
amounts of hydrogen sulphide and other trace gases. Biogas may be
upgraded to biomethane (energy value equivalent to that of natural
gas) by removing the CO2. The most widely used technologies are
water scrubbing, chemical scrubbing and pressure swing adsorption (PSA). The cost of upgrading biogas to biomethane varies
depending on the technology used and the volumetric flow rate of
biogas processed. The literature suggests a range of costs from
V0.11to 0.25/m3n biomethane, for plant capacities of 100e1000 m3n/
h biogas [25]. By viewing this as a CO2 capture process, the cost per
tonne of CO2 captured would range from V68 eto 154 (assuming
55% methane). Thus the cost of carbon capture in a P2G process
equates to V0.13 e 0.31/m3n CH4. The difference in upgrading costs
E.P. Ahern et al. / Renewable Energy 78 (2015) 648e656
653
Table 1
Results of sensitivity analysis.
Number of operational hours
Total energy consumed by P2G (PJ)
Average price of electricity (V/MWh)
Annual CH4 production (Mm3n)
Electricity cost per m3n CH4
Total renewable gen þ curtailment (PJ)
Curtailment (PJ)
Curtailment (%)
Reduction in curtailment (PJ)
Avoided cost (MV)
Base
50 MW V50
50 MW V100
e
e
e
e
e
81.82
9.62
11.75%
e
e
4114
0.73
V57.65
11.6
V1.01
81.82
9.35
11.43%
0.27
V3.71
8713
1.57
V80.99
24.9
V1.42
81.82
9.17
11.21%
0.45
V6.15
quoted is mainly due to the scale of the upgrading plant. A very
significant cost reduction is seen between capacities of 250 m3n/h
and 1000 m3n/h. After about 1500 m3n/h, there is little cost benefit to
be achieved by further increasing the capacity [26].
3.3. Optimal model for P2G systems
3.3.1. Biological power-to-gas systems
Biological P2G systems negate the need for expensive biogas
upgrading if biomethane is to be produced and injected to the gas
grid or used as a transport fuel. In essence if the P2G system costs
less than conventional biogas upgrading (V0.11e0.25/m3n CH4) then
carbon capture may be considered free. This is a very significant
advantage. The methanation stage may take two different forms.
“In-situ” systems involve Introducing hydrogen into the anaerobic reactor. This may cause the pH to rise inside the reactor, as the
hydrogenotrophic methanogens consume CO2 which would
otherwise form a bicarbonate buffer; this may inhibit microbial
activity especially at higher loading rates [27]. The “in-situ” process
may allow the methane content in the biogas to be increased from
about 50% to over 75% [28]. This leads to approximately a 50% increase in the energy output of the reactor. However, further upstream upgrading will still be required to remove the remaining
CO2 if the gas is to be used as a transport fuel or grid-injected.
“Ex-situ” upgrading takes place in a separate bioreactor containing only hydrogenotrophic methanogens. It has been suggested
that despite the additional CAPEX costs, ex-situ upgrading is preferable to in-situ upgrading as it avoids many of the biological and
mechanical challenges present in anaerobic digestion. The ex-situ
process may be fed with CO2 from a biogas upgrading system.
However it is preferable to feed raw biogas to the ex-situ process as
this can replace the traditional biogas upgrading step (Fig. 4).
Typically the traditional biogas upgrading step (such as water
scrubbing) would cost approximately 25% of the CAPEX of the
whole biomethane facility and be energy intensive (consume
0.5 kWeh/m3n biomethane) [29]. The methanogens are fed with
4 moles of H2 for each mole of CO2, as well as a nutrient medium to
maintain the microbial population. Industry sources indicate that it
should be possible to achieve grid-injection standards using this
technique.
Hydrogen is 500 times less soluble in water than CO2 at 60 C, so
getting it into solution is the limiting step in both “in-situ” and “exsitu” processes. The solubility of the gas increases with partial
pressure. Smaller bubbles have higher partial pressures, so techniques to minimise the size of the hydrogen bubbles can assist in
this process. Ideally, the hydrogen would be diffused directly into
solution. This has been achieved at lab-scale, where the H2 is
injected into the reactor via micro-porous ceramic diffusers [30]
and hollow fibre membrane (HFM) modules [31].
The cost of carbon capture is in effect negligible for biological
methanation. “Ex-situ” biological methanation also removes the
Fig. 4. Ex-situ biological methanation.
need for a traditional gas up-grading system, potentially reducing
the capital spend on a biomethane facility by 25%.
3.3.2. Demand driven biogas
Biogas produced from anaerobic digestion can either be used in
a combined heat and power (CHP) plant or upgraded to biomethane for injection to the natural gas grid. Its end use may be
renewable heat, renewable electricity or renewable transport fuel.
Where biogas is used in on site CHP, there is potential for biogas to
assist in the balancing of the electrical network, subject to the heat
demand profile. By varying the feeding rate and the time of feeding
of the reactors, the gas production rate may be controlled. The
Sobacken biogas plant at Borås, Sweden is fed once a day for
10 hours. As a result, the biogas production has daily peaks and
troughs, as illustrated in Fig. 5. Biogas production ranges from
approximately 75e450 m3n/h, giving a peak to trough ratio of 6. The
methane content in the biogas typically varies from 63% to 72%. If
the biogas were to be used in a CHP plant, it may be possible to
match the peak with that of the daily electrical load profile.
The potential of using biogas to balance variable production of
electricity can be best appreciated taking Germany as an example,
which has ca. 8000 anaerobic digesters. For example, if these facilities had a combined average capacity of 4000 MWe, then
applying the same production rates as those at Borås could give a
production range of 1143e6587 MWe. Another method of matching
gas production peaks to electrical load profiles is to store biogas and
only convert to electricity during peak electricity periods.
3.3.3. Optimal P2G system
The optimal model suggested by the authors (Fig. 6) has many
benefits, for the developer and for the regulator. The plant would
utilise a model whereby both CHP and gas grid injection systems
co-exist. Demand driven biogas concepts would be employed so
that at times of peak electricity demand, renewable electricity may
be produced. At times of low demand for electricity, curtailed
renewable electricity would be converted to hydrogen and reacted
with CO2 in the biogas to produce biomethane for gas grid injection
(for ultimate use as a renewable transport fuel). An “ex-situ” process would negate the need for a conventional upgrading system
and thus save cost. The methane output of the system is greatly
enhanced as CO2 is converted to CH4 adding to the original CH4 in
the biogas.
3.4. Potential resource of renewable gas in Ireland
In the proposed model the resource of P2G relies on the availability of biogas. Table 2 shows the biomethane potential from four
feedstocks (agricultural slurry, slaughter waste, OFMSW and grass)
based on previous published work [16, 17].
654
E.P. Ahern et al. / Renewable Energy 78 (2015) 648e656
€ , Sweden).
Fig. 5. Biogas production at Sobacken biogas plant at Borås, Sweden. (Source: Borås Energi och Miljo
The P2G potential combined with the biogas resource is
assessed here, assuming an overall efficiency of 60% conversion of
electricity to methane. This is made up of electrolysis (75% conversion efficiency) and methanation (80% conversion efficiency).
The total energy available from P2G is of the order of 83% of the
energy in the biomethane without biological methanation.
As a means of supplying renewable transport fuel P2G would
cover over 8% of projected energy in transport for 2020 in Ireland.
Allowing for a weighting of 2 it could allow for 17.7% RES-T.
Including for the methane in the biogas the overall potential for
RES-T is close to 38%. This is a very significant resource. It is
supplied while helping to balance variable renewable electricity
with electricity demand, while upgrading biogas to biomethane
and by storing renewable electricity and converting to a transport
vector.
3.5. Financial sustainability of P2G
3.5.1. Cost of hydrogen
The capital cost of electrolysis can vary significantly by technology type. PEM technology is the most expensive, and may cost
up to V3 M for a 400 m3n/h facility. Alternatively, alkaline technology may cost in the range of V1.3e2.1 M for a similarly sized plant
[28]. A plant of about this size would be required to upgrade the
biogas from a 500 kWe biogas facility (producing 100 m3n/h CO2).
Benjaminsson et al. [28] in estimating the total cost of P2G
systems reported a cost of hydrogen production (including for
capital costs, electricity grid costs, maintenance costs and electricity costs) in the range of V1.22eV1.60 per m3n CH4 [28].
3.5.2. Cost of carbon capture
The cost of carbon capture from ambient air (V1.46 per m3n of
CH4), from thermal power plants (V0.02e0.18 per m3n of CH4) and
from biogas facilities (V0.11e0.25/m3n) is expensive. However, if
biogas is used directly in a biological P2G system, this cost can be
avoided. For comparison purposes an upgrading system for 200 m3n
of CO2 per hour of biomethane cost V3.33 M [29]. Thus it may be
said that the capital cost of biogas upgrading is similar to the capital
cost of the alkaline technology system for production of hydrogen.
Using biological P2G as an upgrading system substitutes for conventional biogas upgrading, saving the capital cost equivalent of the
electrolysis system.
Fig. 6. Co-location of CHP and biological methanation.
E.P. Ahern et al. / Renewable Energy 78 (2015) 648e656
655
Table 2
Total potential of renewable gas in Ireland as a renewable transport fuel.
Agricultural slurries
RES-T from anaerobic digestion of selected substrates
Feedstock (Mt/a)a
CH4 yield (m3n/t)a
CH4 from AD (Mm3n/a)a
Practical resource from AD (PJ/a)b
Percentage of energy in transport (%)c
RES-T from AD (%)d
RES-T from biological Power to Gas
% CO2 in biogas
CO2 from AD (Mm3n/a)
H2 required (Mm3n/a)e
Electricity required to provide H2 (PJ/a)f
Energy from Power to Gas (PJ/a)g
CH4 from Power to Gas (Mm3n/a)
Percentage of energy in transport (%)
RES-T from Power to Gas (%)h
RES-T from renewable gas
RES-T from AD and P2G (%)
a
b
c
d
e
f
g
h
Slaughter waste
OFMSW
Grass
Total
2.79
17.8
49.76
1.88
1.00
2.00
0.21
86
18.08
0.68
0.36
0.72
0.22
68
14.98
0.57
0.30
0.60
4.16
107.6
447.59
16.07
8.55
17.10
7.38
71.9
530.41
19.20
10.21
20.42
45
40.71
162.85
2.63
1.58
41.72
0.84
1.68
45
14.79
59.16
0.95
0.57
15.16
0.30
0.6
35
8.07
32.26
0.52
0.31
8.27
0.17
0.34
45
366.21
1464.84
23.63
14.18
375.32
7.54
15.08
e
429.78
1719.13
27.73
16.64
440.47
8.85
17.7
3.68
1.32
0.94
32.18
38.12
From Singh et al. [16] and Wall et al. [17].
Energy value of CH4 taken as 37.8 MJ/m3n.
Energy in transport in 2020 expected as 188 PJ in Republic of Ireland.
Residues and grasses are allowed a weighting of 2 in Renewable Energy Directive.
H2 required at 4 times the volume of CO2.
Energy value of H2 taken as 12 MJ/m3n. Electricity converted to H2 at 75% efficiency.
Overall electricity to H2 efficiency of 60% (80% * 75%).
Power to Gas allowed a weighting of 2 in RED.
3.5.3. Biofuel obligation certificate
There is a Biofuel Obligation Certificate (BOC) system in place in
Ireland operated by the National Oil Reserves Agency (www.nora.
ie). There are three aspects of this scheme that support the sale
price of gaseous fuel from non-biological origin (P2G): the cost of
the certificate itself; the eligibility to receive two certificates; and
the gas to liquid conversion factors.
The certificates trade within a wide range (V0.13e0.36). The
value of the certificate will (by market forces) be less than the
difference in cost of one litre of imported ethanol and biodiesel
with 1 L of imported petrol and diesel. As of 2014 this differential is of the order of V0.38/L. This obviously varies by type
and source of biofuel.
Biofuels produced from specific feedstocks are eligible to receive
two BOCs. These include biodegradable waste, residues, nonfood cellulosic materials, ligno-cellulosic materials, and algae.
These substrate/biofuel systems equate to those that may be
considered at 2 times their energy content for the purposes of
meeting the 2020 Renewable Energy Directive target [14]. Thus
as per Section 1.4 renewable gaseous fuels from non-biological
origin (P2G) systems should also receive two BOCs.
Gaseous fuels with an energy value in excess of 35 MJ/m3n are
liable to a conversion factor of 1.5 when converting a unit volume of gas to a unit volume of liquid transport fuel (http://www.
nora.ie). Thus gaseous fuel from P2G systems is liable to receive
3 BOCs or V0.39e1.08 per m3n methane.
3.5.4. Revenue from sale of renewable gaseous fuel as a transport
fuel
In Ireland natural gas sells at V0.03/kWh. If we consider that
methane has an energy value of 37.7 MJ/m3n (10.4 kWh/m3n) then
this equates to V0.29/m3n. To this the BOC revenues may be added.
Thus the revenue from 1 m3n of methane from a P2G system, when
sold as transport fuel, is in the range V0.68/m3ne1.37/m3n. If the
midpoint of this range is chosen then the revenue is of the order of
V1.03/m3n or over V1/L diesel equivalent.
3.5.5. Financial viability
Using the “ex-situ” process the benefit of P2G includes for a
saving of V0.13e0.31/m3n through substitution of a conventional
biogas upgrading system [29]. To this must be added the return
on gas as a transport fuel. Thus in total the methane from a
P2G system has a potential financial benefit in the range
V0.81e1.68/m3n.
Benjaminsson et al. [28] previously estimated a production cost
of V1.40e1.47/m3n CH4 produced via P2G using two different biological processes [28]. These values assume that excess heat
generated in the process can be sold. As such, the P2G process could
be financially viable should the higher values be obtained with the
BOCs. With modest advances in process efficiency and operational
know-how, as well as cost reductions according to economies of
scale as the systems become more widely used, the process may
very soon become quite attractive.
4. Conclusions
Use of a PLEXOS model has shown that as P2G systems assist in
reducing wind curtailment levels, the electricity required to produce hydrogen may be significantly cheaper than market prices.
P2G systems also require cheap sources of CO2. Use of biological
methanation systems removes the requirement for traditional
biogas upgrading (saving 25% of the capital cost of a biomethane
system) whilst providing the required CO2. The optimal model of a
P2G system is suggested whereby biological methanation at a
biogas facility is used to produce renewable gaseous transport fuel
at times of low electrical demand.
Ireland is at an early stage in constructing biogas plants. A
mature biogas industry would allow production of biomethane to
satisfy 10% of energy in transport. An associated biological P2G
system would allow an 83% increase in methane output. Allowing
weightings from the Renewable Energy Directive the combined
output of methane would facilitate close to 38% RES-T in Ireland.
The Biofuel Obligation Certificates system, as operated in Ireland,
would allow financially viable methane be produced.
656
E.P. Ahern et al. / Renewable Energy 78 (2015) 648e656
Acknowledgements
This research was funded by Science Foundation Ireland (SFI)
centre MaREI (12/RC/2302). Supporting funding was obtained from
is Eireann).
Ervia (formerly Bord Ga
The International Energy Agency (IEA) Task 37 and the Swedish
Gas Technology Centre, Malmo provided valuable input through
debate and discussion of these issues.
Ian Kilgallon of Ervia, Henry Smyth and Brendan Murphy of the
is Group provided valuable discussion, debate and data
Bord Ga
input on these topics.
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