Draft VII 07/06/2012
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Published by the Institution of Gas Engineers and Managers
2 Draft VII 07/06/2012
Preface
This paper, Biofuels: Analysis of the various biofuel types including biomass, bioliquids,
biogas and bio-SNG, was commissioned by the Institution of Gas Engineers & Managers
(IGEM) in order to carry out quantitative research on the various key elements
associated with biofuels and the associated supply and delivery chain.
It will also aim to report on the future developments of biofuels here in the UK.
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Nomenclature
Anaerobic Digestion
AD
Bio-Synthetic Natural Gas
Bio-SNG
Biomethane to Grid
BtG
Compressed Biomethane
CBM
Combined Heat and Power
CHP
Compressed Natural Gas
CNG
Calorific Value
CV
Delivery Facility Operator
DFO
Exajoules
EJ
European Union
EU
Feed-in Tariffs
FITs
Gas Distribution Network
GDN
Gas Distribution Network Operators
GDNOs
Gas Safety (Management) Regulations
GS(M)R
Gas Transporter
GT
Health and Safety Executive
HSE
International Energy Agency
IEA
Liquid Biomethane
LBM
Life-Cycle-Assessments
LCA
Landfill Gas
LFG
Local Operating Procedures LOPs
National Transmission System
NTS
Network Entry Agreement NEA
Polyethylene Pipelines
PE
Pressure Swing Adsorption
PSA
Renewable Energy Directive
RED
Renewable Heat Incentive
RHI
Renewable Transport Fuel Obligation
RTFO
Utility Infrastructure Providers
UIPs
United Nations Educational, Scientific and Cultural
UNESCO
Organisation
Volatile Fatty Acids
VFAs
World Wide Fund for Nature
WWF
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Table of Contents
Preface
3
Nomenclature
4
Figure Listing
6
Table Listing
6
1
7
2
3
Introduction to biofuels
1.1
What are the main drivers behind biofuels?
1.2
What are the potential impacts of using biofuels?
Environmental impacts of biofuel production and use
11
1.2.2
Social and economic impacts of biofuel production and use
12
1.2.3
Technical issues that could act as blockers
13
1.2.4
How can we ensure biofuels are sourced sustainably?
14
Biofuel production from biomass
15
2.1
What quantities of biomass are currently produced?
16
2.2
What are the sources of raw biomass?
16
2.3
Biomass pre-treatment and utilisation
17
2.4
How do you convert biomass?
18
2.4.1
Converting biomass to bioethanol
18
2.4.2
Converting biomass to biodiesel
19
Biofuels used for transport – a UK perspective
Types of feedstock
3.1.1
3.2
20
21
Sources of biofuel to the UK
21
Companies in the UK making bioethanol and biodiesel
Biogas
21
23
4.1
Production of biogas from anaerobic digesters
24
4.2
Composition of biogas from anaerobic digesters
25
4.3
Processing biogas from anaerobic digesters
26
4.3.1
4.4
Biogas cleaning methods
26
Biomethane utilisation
28
4.4.1
Heat production
29
4.4.2
Electricity production
29
4.4.3
Vehicle fuel
29
4.4.4
Injecting biomethane into the UK gas grid
30
4.5
5
10
1.2.1
3.1
4
9
The biogas utilisation outlook
36
Bio-SNG
5.1
39
Bio-SNG production using gasifiers
40
6
Summary of conclusions
43
7
Acknowledgements
45
8
References
46
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Figure Listing
Figure 1: Some types of biofuel feedstock ...............................................................7
Figure 2: Examples of 1st and 2nd generation biofuel sources (corn and algae) .............. 8
Figure 3: Global trend in biofuel production by region (IEA data) .............................. 10
Figure 4: GHG savings of biofuels compared to fossil fuels ....................................... 14
Figure 5: Classification of biofuel types ................................................................. 16
Figure 6: Sources and types of biomass materials for conversion into bioenergy ......... 17
Figure 7: The main steps for the fermentation of sugar-containing crops to ethanol ..... 19
Figure 8: The production process of methyl ester (biodiesel) and glycerol .................. 19
Figure 9: Comparison between biodiesel finished product and waste vegetable oil ....... 20
Figure 10: Bioethanol feedstock ........................................................................... 21
Figure 11: Biodiesel feedstock ............................................................................. 21
Figure 12: Britain’s first biofuels refinery owned by British Sugar .............................. 22
Figure 13: The Ensus plant was opened in 2009 ..................................................... 22
Figure 14: Example of an AD plant configured to produce energy from bio-waste
feedstock .......................................................................................................... 25
Figure 15: Overview of the physical absorption of CO2 ............................................. 28
Figure 16: Econic refuse truck trialled in Sheffield ................................................... 30
Figure 17: East Midlands Airport’s bus powered by Gasrec-produced biomethane ........ 30
Figure 18: Didcot’s biomethane to grid process overview ......................................... 33
Figure 19: Biogas production in Germany between 2000 and 2009 ............................ 39
Figure 20: A schematic diagram of the British Gas Lurgi slagging-bed-gasifier ............ 41
Figure 21: Overview of the bio-SNG production process........................................... 42
Table Listing
Table 1: Classification of 2nd generation biofuels from lignocellulosic feedstocks ............ 9
Table 2: The Biofuels Impact Matrix (BIM) ............................................................. 11
Table 3: Typical composition of biogas .................................................................. 23
Table 4: Summary of the GS(M)R under normal conditions (15°C, 1013.25 mbar) ...... 31
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1
Introduction to biofuels
1. Biofuels are a type of fuel derived from organic matter (broadly described as biomass)
produced by living organisms i.e. plants and animals. Biofuels can also be referred to as
substitutes for fossil fuel sourced mainly from a range of agricultural and energy crops,
forests and waste streams1. Examples of sources include energy crops such as Jatropha
and Camelina, short rotation coppice (SRC) willow and timber, waste oils and
kitchen/food waste, agricultural and forestry residues, industrial bio-wastes and more
novel feedstocks such as algae.
Figure 1: Some types of biofuel feedstock
2. The uses of biofuels are varied; unprocessed biomass can be used to generate
electricity via steam turbines and gasifiers, or heat by directly combusting the raw
material. Biomass can also be converted to bioliquids and used as fuels for transport, as
is the case with bioethanol and biodiesel. Finally, biomass can be converted to an
energy-rich gas (biogas or bio-SNG) that can be used in boilers and gas turbines to
generate heat and electricity, used in gas-fuelled transport as compressed biomethane
(CBM) or supplied to the gas grid.
3. Although biofuels have the potential to be a renewable alternative to conventional
fossil fuels, there are various social, economic, environmental and technical issues
surrounding their production and final end-use. Currently, many governments around
the world have implemented goals to replace a certain percentage of transportation fuel
1
http://www.dft.gov.uk/topics/sustainable/biofuels/
7 Draft VII 07/06/2012
and natural gas demand with biofuels and this trend looks likely to continue. In the EU,
member states are mandated under the Renewable Energy Directive (RED) to replace a
proportion of land transport fuel with renewable fuels. In the UK, as of April 2012,
vehicle fuel companies are obligated under the Renewable Transport Fuel Obligation
(RTFO) to blend fuel sold with 4.5% biofuel2, increasing to 10% by 2020. Meeting such
goals will require adopting measures to ensure that the issues surrounding the use of
biofuels are dealt with, and the fuel itself is sourced sustainably.
Figure 2: Examples of 1st and 2nd generation biofuel sources (corn and algae)3
4. Biofuels can be categorised into two major types: 1st generation biofuels and 2nd
generation biofuels. 1st generation biofuels are biofuels currently on the market today
produced largely from food crops e.g. corn (see Figure 2 above) and 2nd generation
biofuels are those fuels produced by utilising the whole plant rather than just the
sugar/oil component of the food crops (these are usually referred to as lignocellulosic
feedstocks). Novel sources such as algae (see above) are also referred to as 2nd
generation. The main reason why 2nd generation biofuels are being considered is to avoid
the “food vs. fuel” controversy around the use of 1st generation biofuels.
2
3
http://www.official-documents.gov.uk/document/other/9780108508868/9780108508868.pdf
http://www.safnw.com/2011/05/photo-captions/
8 Draft VII 07/06/2012
5. Although they are more difficult (and expensive) to process and the energy yields per
kilogram of input material may appear to be less, 2nd generation biofuels are able to use
the non-food part of food crops, waste materials and most importantly they could be
grown on land that is not suitable for growing food crops e.g. very poor quality land,
land on slopes and brownfield land. As a result the use of 2nd generation biofuels could
potentially contribute to increasing the economic competitiveness of biofuels against
conventional oil and gas.
6. Table 1 is an overview of the different conversion routes for 2nd generation biofuels:
Biofuel group
Bioethanol
Specific biofuel
Production process
Cellulosic ethanol
Advanced enzymatic hydrolysis
and fermentation
Synthetic
Biomass-to-liquids (BTL)
biofuels
Fischer-Tropsch (FT) diesel
Gasification and synthesis
Biomethanol
Heavier alcohols (butanol and mixed)
Dimethyl ether (DME)
Biogas
Bio-synthetic natural gas (SNG)
Gasification and synthesis*
Bio-methane
Anaerobic digestion
Table 1: Classification of 2nd generation biofuels from lignocellulosic feedstocks4
1.1 What are the main drivers behind biofuels?
7. The main factors driving the use of biofuels forward include the need to secure our
energy supplies, the need to reduce our over-dependence on fossil fuels and the legallybinding obligation to reduce our greenhouse gas (GHG) emissions5. Also, the fact that
biofuels can be sourced and produced locally is a major driver and an added advantage
for countries highly dependent on importing energy supplies, as well as for rural villages
that are off any energy grid.
8. The International Energy Agency (IEA) suggests that by 2050, biofuels could meet
about 27% of total global transport fuel demand, as well as save 2.1 gigatonnes (109
tonnes) of CO2 emissions per year that would otherwise have been produced from fossil
fuels6. This claim has been reflected in the amounts of biofuels traded globally.
9. In 2010 the global production of biofuels increased by 17% to 105 billion litres, up
from 90 billion litres the year before. Comparing this figure with the amount of oil
4
5
6
http://www.iea.org/papers/2008/2nd_Biofuel_Gen.pdf
http://www.eubia.org/107.0.html
http://www.iea.org/papers/2011/biofuels_roadmap.pdf
9 Draft VII 07/06/2012
consumed in the same period, recorded at 5074 billion litres, puts the global production
Mtoe (million tonnes of oil equivalent)
of biofuels into perspective.
Figure 3: Global trend in biofuel production by region (IEA data)7
1.2 What are the potential impacts of using biofuels?
10. Due to the possible reduction in greenhouse gas (GHG) emissions achievable,
biofuels are regarded as viable substitutes to fossil fuels. This possible reduction is
mainly due to the carbon present in the plant matter of biofuel feedstocks which
originates from the CO2 absorbed from the atmosphere by the plants during their lifecycle. This is effectively the same carbon matter emitted as CO2 during the use of
biofuels as a result they are referred to as carbon neutral i.e. does not emit additional
carbon to the atmsophere. However, there is still a lot of concern on the production of
the feedstocks used to manufacture biofuels; most of which are based on their overall
impact on the environment and the wider economy. There are also some technical
constraints such as the amount of fossil energy used during production which could act
as blockers to the development of biofuels.
11. The potential impact of using biofuels depends on a number of factors. The largest
and most important factor is the environmental impact of producing and using biofuels
which depends on how the feedstocks are produced and how much pollution the final
product causes when it is assessed on a ‘cradle to grave’ basis. Table 2 presents a visual
representation of the categorisation of the various impacts of biofuels.
7
http://www.iea.org/papers/2008/2nd_Biofuel_Gen.pdf
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Environmental
Loss of
biodiversity
Stress on water
Land-use
Atmospheric
pollution
Cost effectiveness
Energy usage
x
Social & economic
impacts
x
x
x
x
Technical issues
x
x
x
x
x
x
Table 2: The Biofuels Impact Matrix (BIM)
1.2.1 Environmental impacts of biofuel production and use
12. The impacte biofuel production has on the environment are very delicate issues.
These include the issues associated with land used for biofuel feedstock production, the
stress that cultivation of biofuel crops put on water resources (water is required for
irrigation purposes in some climates), the threat of possible biodiversity loss and the net
change in carbon emissions as a result of the final biofuel end-use.
13. Issues on biodiversity and land-use go hand in hand. Biodiversity loss in a given
ecosystem usually depends on the type of biofuel crop being planted, as well as the
previous use of the land. This loss occurs when land with high biodiversity is converted
into a mono-cultural plantation. Also if the land is used to grow energy crops rather than
food crops, as is the case with the Cerrado in Brazil, it then begins to attract a lot of
negative publicity. According to the World Wide Fund for Nature (WWF) the Cerrado,
which is one the world’s most diverse savannah, is now used to grow soya and has
resulted in a less diverse plantation. This monoculture has also led to the destruction of
the local habitat at a rapid rate, similar to the scale of destruction experienced by the
Amazon rain-forest due to logging and land clearance8.
14. In terms of atmospheric pollution, biofuels are reported to be able to achieve
significant carbon reductions when compared to fossil fuels. But there is still a lot of
debate around these carbon savings as some arguments suggest that any potential
reduction in carbon is partially offset by the fossil energy required for the cultivation,
harvesting, processing and transportation of the biofuels produced. This again depends
on the type of crop that is cultivated, as the levels of energy produced and used in these
activities vary significantly with different crops.
15. Previous land-use is another factor in the net difference in carbon emissions from
the production and use of biofuels. An illustration is a scenario where a piece of land that
has not been cultivated before, such as woodland or forest, is converted to produce
8
Soya and the Cerrado - http://assets.wwf.org.uk/downloads/soya_and_the_cerrado.pdf
11 Draft VII 07/06/2012
feedstock for biofuels. When that piece of land is cultivated for the first time, it may
release substantial amounts of carbon that were previously stored and buried in the soil
and in the plant life previously present on it. Such land-use changes could result in the
net increase in carbon emissions on a ‘field to wheel’ basis, until the crop production is
carried out over many decades9.
16. Finally, water is needed for irrigating land used for the cultivation of crops in some
climates. Using water to irrigate land used for biofuels therefore puts a strain on the
water resources available for other uses in that geographical area. The issue of water
pollution also arises from runoffs and the waste created during the production of
biofuels. Other water-related issues include intricate issues such as eutrophication (the
measure of how an ecosystem responds to the addition of artificial resources), nutrient
losses and oxygen depletion that could affect ecological functioning in surface waters10.
1.2.2 Social and economic impacts of biofuel production and use
17. The social implication of using 1st generation biofuels is the risk of diverting precious
resource from where it is needed most, for example, using corn which is a major
foodstuff to produce biofuels. This usually leads to the increase in the global market
price of the commodity because of the reduced quantities produced specifically for
feeding.
18. Some research studies have cited examples in the US where corn is used to produce
ethanol; 26% of the country’s corn harvest was used to produce ethanol in 2009 which
led to a 21% increase in the price of corn. ActionAid11, a major international anti-poverty
and non-governmental organisation, argue that global food prices which have been
pushed up in recent times is as a result of the huge amount of food crops currently used
for biofuel production.
19. Nevertheless, there are still some positive socio-economic impacts of producing
biofuels. Some researchers argue that growing, cultivating and utilising energy crops
creates green jobs in developed countries and alleviates poverty. However, it should be
noted that, in an economic context, the production and supply of biofuels largely
depends on policy, regulatory or investment support (usually in the form of subsidies)
from the government. Recent research commissioned by Friends of the Earth12 suggests
that motorists in the UK could be paying up to £2 billion extra at the pump by 2020, due
to the use of biofuel in petrol and diesel mandatory under the EU’s Renewable Energy
Directive (RED).
9
http://www.dft.gov.uk/topics/sustainable/biofuels/sustainability/
http://unesdoc.unesco.org/images/0018/001831/183113e.pdf
11
http://www.actionaid.org.uk/doc_lib/costofbiofuels.pdf
12
Friends of the Earth, RSPB & Actionaid. Biofuels in 2011: A briefing on the current state of biofuel policy in
the UK and ways forward.
10
12 Draft VII 07/06/2012
1.2.3 Technical issues that could act as blockers
20. There are a number of technical issues associated with biofuels, most of which are
around the amount of energy used in the farming and cultivation stages of the
feedstocks and the amount of energy (in terms of fossil fuels) used to transport and
convert the feedstocks into the final biofuel product. This is characterised by the “net
energy gain” which is defined as the amount of energy released from the fuel less the
amount of energy put into the manufacture of the fuel. The biofuel is regarded as
unsustainable if this works out to be a negative number. Indeed biofuels may require
higher energy input per unit of energy content produced than fossil fuels. This energy
input, however, varies with the biomass stock used and the geographical characteristics
specific to where they are produced.
21. Figure 4 shows the GHG savings possible with biofuels based on the life-cycleassessments (LCA) of some selected biofuel feedstocks. The percentage values indicate
the net GHG savings compared with allowing the plants to grow and naturally fall on the
forest floor to decay. For example, the GHG savings for bioethanol obtained from sugar
cane that can be achieved is between 70-143%. The upper limit is greater than 100%
because the natural decay of sugar cane produces methane which is 20 times more
potent as a GHG than carbon dioxide (CO2)13. In effect, using these plants as feedstock
for biofuels avoids the release of methane that would have otherwise occurred if it was
allowed to grow and decay naturally.
22. Palm oil, from according to the figure, could cause a 2070% increase in GHG. This
excessively large increase may be due to a different way of calculating the GHG
emissions based on the LCA. One common assumption with GHG calculations is that
virgin rainforest may have been cleared to make land space for the palm oil plantation
and the argument is that this new plantation, during its growing process, is much slower
and absorbs substantially less CO2 than the rainforest it replaced. This means the
rainforest was absorbing more CO2 per hectare of land than the new palm oil
plantation14.
13
http://www.unep.org/resourcepanel/Portals/24102/PDFs/Assessing_Biofuels_Summary.pdf
IGEM interview with Chris Hodrien, technical consultant at Timmins CCS and lecturer at the University of
Warwick
14
13 Draft VII 07/06/2012
Figure 4: GHG savings of biofuels compared to fossil fuels15
IGEM understands that the use of life-cycle-analysis (LCA) at present is
controversial because there is still no globally accepted standard way of
performing LCA calculations. IGEM understands that the main issue with this
technique is that of ‘how far back down the biofuel chain do you go’ in the
calculation process in terms of what is included or excluded (e.g. fertilisers
used to grow feedstock, energy used during the mining process of the minerals
used to manufacture fertilisers, etc).
IGEM,
however,
understands
great
strides
are
being
made
by
the
Intergovernmental Panel on Climate Change (IPCC) to come to a global
agreement on LCAs.
1.2.4 How can we ensure biofuels are sourced sustainably?
23. Improvements to biofuel systems can be achieved by finding ways to mitigate some
of the adverse effects they have on the environment, human lives and natural resources.
On the production side, biofuels made from organic waste are environmentally more
favourable and cheaper than biofuels sourced from energy or food crops.
24. On the utilisation side, there are a number of initiatives that can ensure biofuels are
sourced sustainably. For example, UK fuel companies are currently obligated under the
15
Menichetti, E. and Otto, M. (2008) Existing knowledge and limits of scientific assessment of the sustainability
impacts due to biofuels by LCA methodology. Final report.
14 Draft VII 07/06/2012
Renewable Transport Fuel Obligation (RTFO) to blend 4.5% biofuel in the fuel they sell.
However, the RTFO also obligates the suppliers of biofuels to report on the carbon
emissions savings and sustainability of the products they have supplied. Suppliers who
do not provide the necessary documentation will not be eligible for the RFTO certificates
issued.
25. Sourcing biofuels from sustainable areas is absolutely vital to the future use of this
alternative energy. This, according to the World Wide Fund (WWF), is the only way
governments can start to permit biofuels to be used on a larger scale. They argue that
biofuels must deliver GHG and carbon life-cycle benefits over conventional fuels and
ensure the effective use of natural resources and land-use planning in order to safeguard
grasslands and natural forests16.
26. Another study titled the “Gallagher Review of the indirect effects of biofuel
production” suggests that the production of biofuels must target idle and marginal land
and the use of wastes and residue streams. This would ensure that biofuel production
activities are sustainable by not competing with land for food crops and not result in the
net emissions of GHGs and the loss of biodiversity through habitat destruction17.
IGEM understands that sourcing biofuels sustainably is important if it is to
command a major share of the UK energy mix. However, IGEM believes this
cannot happen unless there is some sort of sustainably certified supply chain
that encompasses all the different individual biofuel interest areas.
IGEM welcomes the increasing UK interest in 2nd generation biofuels including
more novel feedstock options such as algae and waste-derived supplies. IGEM
believes that biofuels sourced from organic waste, are not only more
environmentally favourable and cheaper to source than biofuels grown from
energy crops, but can also go a long way to ensuring this energy option starts
to effectively compete both economically and environmentally with other
renewable options.
2 Biofuel production from biomass
27. Biomass refers to the biological material derived from living or recently dead
organisms that is used as feedstock to manufacture biofuels. Although biomass can
either be combusted in isolation or co-combusted with coal to generate electricity, it can
also be converted to liquid transportation fuels (bioliquids) or biogas for gas-specific
power generation.
16
assets.panda.org/downloads/wwf_position_eu_biofuels.pdf
http://www.unido.org/fileadmin/user_media/UNIDO_Header_Site/Subsites/Green_Industry_Asia_Conference
__Maanila_/GC13/Gallagher_Report.pdf
17
15 Draft VII 07/06/2012
Figure 5: Classification of biofuel types
2.1 What quantities of biomass are currently produced?
28. Biomass became the largest source of renewable energy in 2008 generating around
50 exajoules (EJ) (1200 million tonnes of oil equivalent) of bioenergy globally, which
accounted for a 10% share of the total primary energy demand in the same period.
Projected world primary energy demand by 2050 is expected to be in the range of 600 to
1000 EJ and various scenarios indicate that the future demand for bioenergy could be up
to 250 EJ/yr, representing between a quarter of the future global energy mix.
2.2 What are the sources of raw biomass?
29. Most of the biomass used today is sourced from three main areas: forests,
agriculture and waste. This includes virgin wood from the conventional cutting of trees,
wood residues from sawmills and other wood processing industries, agricultural energy
crops, agricultural residues and waste18. All the sources of biomass can be broadly
categorised into woody and non-woody, as illustrated in Figure 6 below:
18
http://www.decc.gov.uk/en/content/cms/meeting_energy/bioenergy/bioenergy.aspx
16 Draft VII 07/06/2012
Figure 6: Sources and types of biomass materials for conversion into bioenergy19
2.3 Biomass pre-treatment and utilisation
30. Biomass can be converted into energy via combustion. During the combustion
process biomass initially loses its moisture after which volatile gases (such as CO, CH4)
are released. These gases contribute to about 70% of the heating value of the biomass.
Finally, the char oxidises and ash remains.
31. The quality of the biomass depends on the type of raw material used and pretreatment method applied prior to combustion. Pre-treatment is applied in order to lower
handling, storage and transportation costs, as well to reduce the need for installing
expensive combustion technology. There are a range of pre-treatment methods available
which are usually matched to the type of combustion technology chosen. Some pretreatment options include compacting and drying using heat. In some cases wood may
be left outside for a number of weeks to dry before they are chipped and fed into a
combustion plant20.
32. Co-firing biomass with coal using conventional coal-fired stations is another
utilisation option that is becoming popular for a number of reasons. One reason is that
the concept of co-firing capitalises on the existing infrastructure already in place and can
enable the stations attain net reductions in GHG emissions. Also, biomass-derived fuels
contain far less sulphur than coal; therefore co-firing can have a positive impact on SOX
19
20
http://www.wgbn.wisc.edu/producers/biomass-sources
http://www.ieabcc.nl/publications/t32.pdf
17 Draft VII 07/06/2012
emissions. Finally, the net efficiency of burning biomass by co-firing in existing power
stations is much higher than using it in dedicated biomass plants. This is to do with the
efficiencies of scale – because co-firing is usually done in a large scale plant that costs
less per tonne of product to build, it is therefore possible to afford a much more
sophisticated energy cycle that can attain much higher efficiencies.
33. In terms of equipment modification, co-firing 5-10% biomass requires only minor
changes in handling techniques and equipment; however, equipment changes are
needed for biomass co-firing exceeding 10%.
2.4 How do you convert biomass?
34. There are 3 primary ways of converting biomass directly into energy21:
 Thermally – biomass can be directly burnt for heating and cooking purposes, or
indirectly in order to generate electricity.
 Thermochemically – biomass can be broken down into solids, liquids and gases by
heating up the plant matter and chemically processed into biogas and liquid fuels.
 Biochemically – biomass liquids can be converted into alcohol by adding bacteria,
yeasts or enzymes to cause the liquids to ferment.
2.4.1 Converting biomass to bioethanol
35. Feedstocks used for the conversion of biomass to bioethanol include food crops such
as corn, sugar cane, sugar beet, grain, sunflower, wheat and straw. After a crop has
been grown and harvested, it is refined further in readiness for conversion. Sugars, for
example, can be recovered using various extraction methods or biochemically using
enzymes. The main biomass to bioethanol conversion mechanism is fermentation e.g.
the fermentation of sugars to produce ethanol22. After the fermentation process has
been completed, the ethanol produced can be distilled in purification columns to increase
the concentration of the product.
21
http://www.centreforenergy.com/AboutEnergy/Biomass/Overview.asp?page=4
http://www.wpi.edu/Pubs/E-project/Available/E-project-042810165653/unrestricted/Ethanol_from_Sugar_Beets_-_A_Process_and_Economic_Analysis.pdf
22
18 Draft VII 07/06/2012
Figure 7: The main steps for the fermentation of sugar-containing crops to ethanol23
2.4.2 Converting biomass to biodiesel
36. The production of biodiesel from biomass involves the conversion of various types of
waste feedstocks, including vegetable oils, animal fats or waste oils, in a reaction
process known as transesterification. Transesterification is the reaction between a
triglyceride and an alcohol, such as ethanol, in the presence of a catalyst (usually
potassium hydroxide) to produce alkyl esters and glycerol. Alkyl ester is the chemical
name for the final biodiesel product and glycerol is the by-product of the reaction.
Figure 8 below shows the chemical process for the production of methyl ester biodiesel:
Figure 8: The production process of methyl ester (biodiesel) and glycerol24
37. After the process has been completed, the catalyst is recovered and the glycerol is
separated out either by drawing it off the bottom of the settling vessel under gravity, or
by using a centrifuge. One major problem with converting biomass to biodiesel is the
lack of a market for the glycerol by-product required to absorb the quantities created if
biodiesel was produced on a large scale. An example of waste vegetable oil feedstock
and biodiesel product is illustrated in Figure 9 below:
23
24
http://www.meadmadecomplicated.org/science/fermentation.html
http://www.esru.strath.ac.uk/EandE/Web_sites/02-03/biofuels/what_biodiesel.htm
19 Draft VII 07/06/2012
Figure 9: Comparison between biodiesel finished product and waste vegetable oil25
3
Biofuels used for transport – a UK perspective
38. The use of biofuels in the transportation sector is vital to the UK’s plan to comply
with the 10% by 2020 renewable energy targets in the EU Renewable Energy Directive
(RED)26. The RED also enforces different mandatory criteria for biofuels around where
these fuels are sourced. In response, the Renewable Transport Fuel Obligation (RTFO)
was introduced in 2005 in an effort to bring the UK in line with the RED targets. RTFO is
a legislation that mandates UK transport fuel suppliers to source a certain amount of the
fuel they supply from renewable sources. It applies to all organisations supplying more
than 450,000 litres of fossil fuel within a given year. So far under the RTFO, 4.3 billion
litres of biofuel have been supplied to the UK fuel market since April 200827.
39. Between April 2010 and April 2011, 1.4 billion litres of biofuel was supplied to the
UK under the RTFO which was equivalent to 3.1% of total road transport fuel used within
that period. Biodiesel and bioethanol accounted for 59% and 41% of the total share
respectively, with a negligible amount taken by biogas (<0.1%)28. Biodiesel and
bioethanol can be safely used in small quantities in current road vehicles without
additional modifications. Currently, blends of up to 5% ethanol (E5) can be sold in the
UK without additional labelling, and a revision following BS EN 590:2009 on
requirements for diesel fuel increased the biodiesel blend from 5% to 7% in 201029.
100% pure biofuels can also be supplied but will not be compatible with all vehicles and
must be labelled with “Not suitable for all vehicles: consult vehicle manufacturer before
use”. Of the two fuels, biodiesel is more widely used across the UK, with the website
“Biodiesel Filling Stations” (biodieselfillingstations.co.uk) providing a list of all the UK
biodiesel outlets that provide higher percentage blends.
25
26
27
28
29
http://kenknee.blogdrive.com/
http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2009:140:0016:0062:en:PDF
http://www.ukpia.com/industry_issues/fuels/biofuels-and-alternative-fuels.aspx
http://assets.dft.gov.uk/statistics/releases/biofuels_april_2011/rtfoaug2011.pdf
http://www.tycofis.co.uk/bio-diesel/joint-statement-on-biofuel.pdf
20 Draft VII 07/06/2012
3.1 Types of feedstock
40. In 2011, the main feedstock contributors to bioethanol production in the UK included
corn, wheat, sugar cane and sugar beet (see Figure 10 below). In comparison, much
cheaper sources such as used cooking oil, soy, oilseed rape and tallow formed the
feedstock mix for biodiesel production (see Figure 11).
Molasses
3%
Other
4%
Sugar
beet
15%
Corn
34%
Sugar
cane
21%
Wheat
23%
Figure 10: Bioethanol feedstock
Tallow
6%
Palm
4%
Unknown
4%
Oil
11%
Used
cooking
oil
50%
Soy
25%
Figure 11: Biodiesel feedstock
3.1.1 Sources of biofuel to the UK
41. Most of the biofuels currently supplied to the UK are sourced domestically (22%),
followed by imports from the USA (17%), Argentina (13%), Germany (9%), Netherlands
(9%) and Spain (6%).
3.2 Companies in the UK making bioethanol and biodiesel
42. British Sugar began producing biofuels in September 2007 at the first UK bioethanol
plant located in Wissington, Norfolk. The plant produces up to 70 million litres of
bioethanol per year, all of which are produced from fermenting sugar beet30. The
30
http://www.britishsugar.co.uk/Bioethanol.aspx
21 Draft VII 07/06/2012
bioethanol produced at the plant is typically blended with unleaded petrol (about 5%
bioethanol) and used in cars.
Figure 12: Britain’s first biofuels refinery owned by British Sugar
43. Another company, Ensus, operates one of the world’s largest cereal grain
biorefineries at Wilton on Teesside. The refinery processes locally grown animal feed
wheat from which over 400 million litres of bioethanol, 350000 tonnes of high protein
animal feed, and 300000 tonnes of CO2 (used for soft drinks and food production), are
produced each year. However, at the time of writing, the refinery had been closed down
since May 2011 due to increasing global prices of 1st generation biofuel feedstock which
form the bulk of the feedstock used at the plant31.
Figure 13: The Ensus plant was opened in 2009
44. Additionally, a new biorefinery in Salt End, Hull, is set to be commissioned by
Vivergo Fuels later this year, with the capacity to produce 420 million litres of ethanol
and 500,000 tonnes of mid-protein animal feed from 1.1 million tonnes of feed wheat
31
http://www.bbc.co.uk/news/uk-england-tees-16516420
22 Draft VII 07/06/2012
per annum32. Vivergo Fuels, a joint venture with BP, DuPont and British Sugar, aim to
supply over 30% of UK ethanol requirements under its Renewable Transport Fuel
Obligation33.
4
Biogas
47. Biogas is the gas produced from the breakdown of organic matter in the absence of
oxygen. The raw gas is typically composed of 60% methane (CH4) and 40% carbon
dioxide, however, depending on the source, other components can exist which include
oxygen (O2), hydrogen (H2), hydrogen sulphide (H2S), siloxanes, ammonia (NH3) and
water vapour (moisture). Table 3 below shows the typical composition of the biogas
mixture.
Compound
Chemical formula
%
Methane
CH4
50–85
Carbon dioxide
CO2
5–50
Hydrogen
H2
0–1
Hydrogen sulphide
H2S
0–3
Nitrogen
N2
0-5
Oxygen
O2
0-2
Table 3: Typical composition of biogas
48. For most purposes, biogas can be divided into two categories: land-fill type and
anaerobic digestion type. Land-fill (LF) type biogas is produced by allowing natural decay
to occur within a land-fill producing a gas that is captured, while anaerobic digestion
biogas is produced in purpose-designed above-ground plants to optimise the gasproducing decay process for greater efficiencies. There is a major environmental driver
to capture the gas produced from the breakdown of organic matter. Naturally decayed
waste, both household waste which is usually land-filled and farm waste, produce a lot of
CH4 which is 20 times more potent as a GHG than CO2. As a result, from a policy point of
view, there is a huge amount CO2 reduction achieved when waste is enclosed in a sealed
tank and the captured methane is burned or flared to produce CO2 as the main byproduct.
49. Biogas can be produced from a range of feedstock including some biomass sources
and waste streams. Waste sources including those from food waste, energy crops, crop
residues, slurry or sewage waste, landfill gas and manure from animals can all be
processed to biogas via AD. The type of feedstock processed is critical to the
32
http://uk.reuters.com/article/2012/02/09/uk-biofuels-vivergo-idUKTRE8181SN20120209
http://www.hydrocarbonprocessing.com/Article/3010578/Refining-Biofuels/BP-to-start-up-Hull-biorefineryin-UK-later-this-year.html
33
23 Draft VII 07/06/2012
performance and overall efficiency of the AD process. The faster the feedstock breaks
down, the better the overall efficiency and gas yields obtained per unit of raw material.
IGEM believes using the anaerobic digestion route (AD) to treat waste, with the
potential to provide energy at the same time, has an important role to play as a
means of avoiding the emission of greenhouse gases (GHGs) from landfill
disposal, some of which are 20 times more potent as a GHG than carbon dioxide
(CO2).
4.1 Production of biogas from anaerobic digesters
50. The anaerobic digestion (AD) process for biogas production can be classified
according to the following categories34:
 The operating temperature of the digester:
Mesophilic (25-45°C) or Thermophilic (50-60°C)
 The state of the organic matter in the digester:
Wet feed (5-15% dry matter) or dry (over 15% dry matter)
 The mode of operation:
Continuous or batch process
 Single or multistage digesters
51. Thermophilic systems are known to provide much faster biogas production rates per
unit of feedstock and cubic metre of digester than mesophilic systems35. The degree of
wetness (or dryness) of the AD system is also a critical operating factor. Dry AD
operations tend to be cheaper to run because there is less water to evaporate but have
high set-up costs per unit of feedstock. Wet AD processes, on the other hand, have
lower set-up costs but higher operating costs than dry AD processes.
52. Biogas digesters can also be operated in either batch or continuous mode. There are
usually technical justifications behind operating the AD in either mode such as the need
to overcome peaks or troughs in gas production which can be accomplished by operating
multiple batch digesters in parallel. It is also possible to run continuous digesters
provided there is a gas holder available on-site big enough to deal with the variations.
53. Anaerobic digestion is essentially a 3 stage biological process. The first stage is the
breakdown of the complex organic molecules into simpler molecules, volatile fatty acids
(VFAs), NH3, CO2 and H2S. The simpler molecules are then further digested to produce
more CO2, hydrogen and acetic acid. The final stage involves further breakdown of the
fatty acids into CH4, CO2 and water. Each of these 3 stages uses completely different
34
35
http://www.biogas-info.co.uk/index.php/types-of-ad.html
http://www.biogas-info.co.uk/index.php/types-of-ad.html
24 Draft VII 07/06/2012
bacteria that operate at different conditions. In a single stage digester, all the bacteria
needed for the process work at a compromise because none of them operate at their
optimum efficiency. In a multistage digester, the 3 stages of the AD process can be
optimised to get bigger gas yields per unit of feedstock. Multistage digesters, however,
are more expensive to build and more complex to control.
Figure 14: Example of an AD plant configured to produce energy from bio-waste feedstock36
54. In addition to generating energy in the form of biogas, AD also produces digestate.
This digestate can be treated and used as a form of renewable fertiliser containing
critical nutrients such as nitrogen and phosphorus. However, the nutrient composition
depends on the feedstock, which implies that, in addition to nitrogen and phosphorus,
the digestate may contain heavy metals and other persistent organic compounds which
may be difficult and expensive to remove for subsequent use.
4.2 Composition of biogas from anaerobic digesters
55. The composition of biogas varies according to origin of the feedstock used in the AD
process. Biogas produced from the various sources vary in the level of CH4, CO2, H2S,
O2, moisture, siloxanes and other contaminants it contains. For example farm biogas –
biogas converted from farm waste – usually has much higher concentrations of H2S,
micro-organisms
and
traces
of
extra
contaminants
such
as
pesticides
and
37
pharmaceuticals. Farm gas also has high NH3 content .
56. Waste water biogas – biogas obtained from converting sewage sludge from
wastewater plants – contains siloxanes and other organic compounds such as aldehydes,
as well as low levels of particulate matter and metals such as arsenic and mercury, all
unique to the source. Organic solid wastes from industry also contain low levels of
36
http://www.defra.gov.uk/publications/files/anaerobic-digestion-strat-action-plan.pdf
Hazards arising from conveyance and use of gas from Non-Conventional Sources (NCS). Research Report
(RR882) prepared by GL Noble Denton for the Health and Safety Executive 2011.
37
25 Draft VII 07/06/2012
arsenic and mercury which, from a UK gas grid perspective, exceeds the current UK
Export Sales Gas Limit38. Biogas from landfill gas sources contain high levels of
hydrogen, organic sulphides and thiols which all need to be removed for subsequent use.
The technical implication of the varying composition of biogas from AD, from a gas grid
utilisation point of view, is that it requires expensive purification technology in order to
meet Gas Safety Management Regulations (GS[M]R).
4.3 Processing biogas from anaerobic digesters
57. Biogas from anaerobic digesters can be processed to a gas with higher CH4 content
referred to as biomethane or renewable gas. The amount of unwanted contaminants
removed from the produced biogas depends on the final end-use of the gas. Most often
water vapour and H2S removal is required, except when the gas is to be compressed and
used as a vehicle fuel then it is recommended that CO2 is also substantially removed39.
When the gas is to be fed into the gas grid it has to meet standards imposed by gas
quality regulations within a particular region, for example the Gas Safety (Management)
Regulations (GS[M]R) for gas conveyance in the UK which requires a CH4 content of
about 95% so it resembles the qualities of natural gas (see section 4.4.4.1.).
58. The need for processing biogas is significant, not least because of the corrosive
nature of H2S, bacteria (via microbially-induced corrosion) and water vapour in the gas.
As a result various methods are deployed to purify biogas, which include processes
whereby the raw biogas stream is absorbed or scrubbed to remove the contaminants,
leaving up to 98% methane per unit volume of the gas stream.
4.3.1 Biogas cleaning methods
4.3.1.1 Water vapour removal
59. Water vapour must be removed in order to meet pipeline quality standards or CNG
vehicle fuel standards. The removal methods for water vapour are either based on the
physical separation of condensed water or chemical drying.
 Physical separation
60. The simplest way of removing water vapour is through refrigeration. The condensed
water droplets are entrapped and separated by either using a demister, where liquid is
separated using microscopic pores, or cyclone separators in which water droplets are
separated using centrifugal forces.
39
http://www.biogasmax.eu/media/2_biogas_production_utilisation__068966400_1207_19042007.pdf
26 Draft VII 07/06/2012
 Adsorption drying
61. The chemical method of gas drying involves elevating the pressure of the gas and
feeding it through a column containing an adsorbent component such as silica. This is a
continuous cyclic process and the bed is regenerated thermally to release the water as
water vapour every few hours.
4.3.1.2 H2S removal
62. H2S removal is required to avoid corrosion issues in piping, compressors, gas
storage tanks and engines. H2S is extremely reactive with most metals, and this
reactivity is enhanced by the presence of water, elevated temperatures, pressures and
concentrations. It reacts with iron oxide or iron hydroxide to form iron sulphide and
water, the iron oxide can then be regenerated using oxygen.
4.3.1.3 CO2 removal
63. CO2 removal is essential for enhancing the energy value of biogas. As the CO2 is
removed, the relative density of the gas is decreased and the calorific value increased increasing the Wobbe Index. There are 3 main methods used commercially for the
removal of CO2 from biogas.
 Physical CO2 absorption
64. One of method of separating CO2 from CH4 is by scrubbing the raw gas with water to
remove CO2, capitalising on the fact that CO2 is more soluble in water than CH4. In this
process, the raw gas is introduced to the bottom of a vertical column at pressure
(typically between 1000-2000kPa). Water is then fed to the top of the column which is
usually equipped with random packing to provide the surface area needed to facilitate
mass transfer between the gas and liquid40. As the gas flows up the column the
concentration of CO2 decreases during which the gas becomes richer in CH4. The
processed biogas then leaves from the top of the column. In order to remove the
methane from the water, the water leaving at the bottom of the column is partially
depressurised in a flash tank. This releases the CH4 rich gas which is recycled with the
untreated biogas. Water is regenerated using a desorption column, where it is brought in
contact with air or steam to strip the CO2 from it. An overview of the process is shown in
Figure 15 below:
40
E. Ryckebosch, M. Drouillon, H. Vervaeren, 2011. Techniques for transformation of biogas to biomethane,
Biomass and Bioenergy, Vol. 35, pp. 1633-1645
27 Draft VII 07/06/2012
Figure 15: Overview of the physical absorption of CO2
 Chemical absorption
65. Alternatively, CO2 can be removed by chemically absorbing it. This method uses an
amine at slightly elevated pressures to absorb the CO2 present in biogas. The amine is
then regenerated with steam or heat to separate and recover the CO2. This is, however,
an energy intensive process compared to other methods for absorbing CO2.
 Cryogenic separation
66. CH4 has a boiling point of -161°C while CO2 boils at -78°C which means that CO2 can
be separated from biogas as a liquid by cooling the gas mixture at elevated pressure.
CH4 can be extracted as a liquid or vapour depending on how the system has been
designed41. This, too, is an energy intensive process.
4.4 Biomethane utilisation
67. Purified biogas or biomethane can be utilised in a variety of ways. The main uses are
listed below42:
 It can be burnt in boilers to provide heat
 It can be used to generate electricity in gas turbines or engines.
 It can be compressed for use as a vehicle fuel
 It can be injected to the gas grid for subsequent use
41
42
http://www.iea-biogas.net/_download/publi-task37/upgrading_report_final.pdf
http://www.aebiom.org/IMG/pdf/Nielsen_text.pdf
28 Draft VII 07/06/2012
4.4.1 Heat production
68. Biomethane can be used to produce heat by burning the gas in boilers or industrial
furnaces. The biomethane content requirements for boilers are not as stringent as those
for other utilisation options, however, H2S, which could lead to the formation of sulphuric
acid, poses a corrosion problem and therefore needs to be removed. It is not absolutely
necessary to remove CO2 and water vapour present in the gas; however, water vapour
can also be a source of corrosion problems in gas nozzles.
4.4.2 Electricity production
69. The use of biomethane for electricity generation or combined heat and power (CHP)
is done in gas turbines and engines. These are both long established and reliable
technologies with thousands of units operating on gases with differing specifications in
different places all around the world. Gas engines have high gas quality requirements,
for example it is typically recommended to reduce the H2S content to values lower than
1ppm (parts per million) and the siloxanes content to 1ppb (parts per billion)43.
4.4.3 Vehicle fuel
70. Biomethane can be compressed in the same way as natural gas and used to run
vehicles. This is usually referred to as compressed biomethane (CBM). There are
currently about 13 million compressed natural gas (CNG) vehicles globally. There are
also vehicles modified to run on liquid biomethane (LBM), however, these are mostly
used in heavy duty type vehicles.
71. Commercial trials of biogas vehicles have suggested that CNG or CBM vehicles could
achieve significant CO2 reductions compared with equivalent diesel vehicles. Also, lower
nitrous oxide emissions and negligible particulate emissions are achievable with CBM
vehicles. However the gas specifications are quite high; it should contain above 95 vol%
CH4 which means that CO2, H2S, NH3, particulate matter and H2O all have to be removed
(although different quality specifications may be applied in different countries).
72. There are 2 ways to get the vehicles to burn CNG or CBM. The first is to convert
existing vehicles so they can run on CNG or CBM. There are gas conversion kits available
on the market to do this. The second way is to use original equipment manufacturer
(OEM) dedicated vehicles.
4.4.3.1 Biomethane for vehicle use – UK case studies
73. Sheffield City Council, in association with Veolia Environmental Services and CNG
Services, successfully trialled biomethane fuelled lorries in 2010. The fleet consisted of
10 Mercedes-Benz Econic lorries (see Figure 16) which were used to collect rubbish
43
http://www.iea-biogas.net/_download/publi-task37/Biogas%20upgrading.pdf
29 Draft VII 07/06/2012
across the city of Sheffield. During the same year, Volkswagen’s Passat Ecofuel made its
UK debut at a Low Carbon Vehicle event held at Millbrook Proving Ground. The car,
which runs on both CNG and CBM, does 0 – 60 mph in 9.5 seconds and can achieve
substantially less CO2 emissions per km than equivalent performance diesel vehicles.
Figure 16: Econic refuse truck trialled in Sheffield44
74. Gasrec, a leading producer of liquid methane fuel in Europe, entered into a trial in
2009 to run an East Midlands Airport transfer bus powered by liquid biomethane (LBM)
(see Figure 17 below). The LBM used was produced from organic waste in existing
landfill sites and by-products obtained from the digestion of biomass sourced from
industries such as food and retail waste.
Figure 17: East Midlands Airport’s bus powered by Gasrec-produced biomethane45
4.4.4 Injecting biomethane into the UK gas grid
75. The most promising method of utilising biomethane would be introducing it into the
natural gas distribution network. There is some work going on in the UK looking into the
feasibility of the concept. The final composition of the injected biomethane depends on
the grid specifications. The requirements are mainly focussed on the amount of CH4,
CO2, O2, H2S and halogen compounds the final gas product contains.
44
45
http://www.cngservices.co.uk/presentations-2/
http://cnch4.com/mediadetails.php?ID=19
30 Draft VII 07/06/2012
4.4.4.1 UK compliance requirements
76. Biomethane injected into the UK gas network must meet the specifications outlined
in the Gas Safety (Management) Regulations (GS(M)R). The GS(M)R approach was
initially developed by the Health and Safety Executive (HSE), and the former British Gas.
The approach uses Wobbe Number, which is a measure of the energy input through an
appliance based predominantly on the discharge through a burner nozzle, as the main
parameter to compare between different gas qualities.
77. The gas distribution network operators (GDNOs) also have to enter a Network Entry
Agreement (NEA) with the suppliers of biomethane into their network. This usually sets
entry requirements detailed under GS(M)R and refines the limits as required to account
for other operational factors. A summary of GS(M)R limits is shown in Table 4 below46:
Property
Range
Hydrogen sulphide (H2S)
<5 mg/m3
Total sulphur (S)
<50mg/m3
Hydrogen (H2)
<0.1 mol%
Oxygen (O2)
<0.2 mol%
Impurities and water and hydrocarbon
The gas shall not contain solids or liquids
dewpoints
that may interfere with the integrity or
operation of the network or appliances
Wobbe number
Between 47.20 and 51.41 MJ/m3
ICF (incomplete Combustion Factor)
<0.48 – normal conditions
SI (Sooting index)
<0.60
Odour
Gas below 7 bar(g) will have a stenching
agent added to give a distinctive odour
Table 4: Summary of the GS(M)R under normal conditions (15°C, 1013.25 mbar)
78. The calorific value (CV) of the biomethane is the most important parameter when it
comes to using it. The calorific value is a measure of heating power representing the
amount of heat released as a gas is burnt. It is dependent on the composition of the gas.
In the UK, gas passing through the national transmission system (NTS) must have a CV
between 37.5 MJ/m3 to 43.0 MJ/m3.
79. In order to avoid transmitting a low energy gas, biomethane is either enriched with
propane to meet the local Flow Weighted Average Calorific Value (FWACV) target or
commingled (blended) with local grid gas (essentially natural gas)47 to minimise the use
of propane.
46
Hazards arising from conveyance and use of gas from Non-Conventional Sources (NCS). Research Report
(RR882) prepared by GL Noble Denton for the Health and Safety Executive 2011.
47
http://gasgovernance.co.uk/sites/default/files/National%20Grid%20Note%20on%20commingling.pdf
31 Draft VII 07/06/2012
80. The calorific value can be measured at 110 different locations on the National Grid
(NG) pipeline system. These are inputted into 13 charging areas in the UK, where a daily
CV average is calculated in order to meet regulations: The daily CV average for each
charging area is calculated using the product of the CV for all the inputs and dividing by
the total volume of gas entering the charging area. Regulations48 mandate that the
difference between the maximum daily CV average (FWACV) and the measured daily CV
average of the input into the charging area must not exceed 1 MJ/m3.
4.4.4.2 How does a biomethane producer connect to the gas network?
81. In the UK, physical connection to the network is facilitated by a licensed Gas
Transporter (GT) (e.g. National Grid, Scotia Gas Networks) or one of the registered
Utility Infrastructure Providers (UIPs) (e.g. Fulcrum, Denholm Pipecare Ltd). The
connection charges are dependent on the size and location of the connection. For
example, if the pipeline nearest to the biomethane plant isn’t large enough to take the
volume of gas produced, additional pipe-work may be required; the costs of which are
incurred by the biomethane producer. At present any connecting pipe-work has to be
owned by a licensed GT49.
82. Alongside the physical connection arrangements, biomethane producers are required
to enter a Network Entry Agreement (NEA) with the GT. This agreement defines how the
network entry facility will operate i.e. who takes ownership of the plant and equipment,
maintenance and operational responsibilities, gas quality specifications and Local
Operating Procedures (LOPs).
4.4.4.3 What equipment is needed for biomethane injection?
83. The following points highlight DECC’s published guidelines on equipments that most
biomethane injection facilities need to have for injection into the gas grid:
 Biogas clean-up facilities – this will enable the gas to meet quality requirements.
 Enrichment unit – to increase the energy content (calorific value) to the level
required.
 Gas quality monitoring equipment – monitoring equipment is used in order to
demonstrate and ensure to the gas transporters and the Health & Safety Executive
(HSE) that biomethane injected is compliant with Gas Safety Management Regulations.
 Metering equipment – to measure the volume of gas injected into the gas network.
 Odourisation equipment – to give the gas its characteristic smell and for it to be
detectable in case of a leak.
48
http://www.nationalgrid.com/uk/Gas/Data/misc/reports/description/
http://www.decc.gov.uk/assets/decc/what%20we%20do/uk%20energy%20supply/energy%20markets/gas_
markets/nonconventional/1_20091229125543_e_@@_biomethaneguidance.pdf
49
32 Draft VII 07/06/2012
 Pressure control equipment – pressure of biomethane needs to be increased by
compression or reduced by a pressure reduction valve to enable safe injection.
 Automatic valve – a valve is required to stop injection if it is not of appropriate
quality.
 Telecommunications equipment – to send data for billing and operational reasons.
4.4.4.4 Biomethane to Grid (BtG) - UK case studies
84. Biomethane was injected into the UK gas grid for the first time when sewage from
over 30,000 homes in Oxfordshire was processed in the Didcot sewage treatment works
producing biomethane which was supplied to about 200 homes.
Figure 18: Didcot’s biomethane to grid process overview50
85. The biomethane production facility was a joint venture between Scotia Gas Networks
and Thames Water, an overview of the process in illustrated in Figure 18 above. The
biogas that was produced at the site underwent a clean-up and upgrading process which
used water wash technology provided by Chesterfield Biogas51. In order to meet
regulations, the biomethane was enriched with propane before it was added to the
national grid52. The Health & Safety Executive (HSE) issued a GS(M)R exemption to
Scotia Gas Networks to allow biomethane to be conveyed in a limited area around
Didcot. This allowed the oxygen content of up to 2% - compared with the limit of 0.2%
set by the GS(M)R - on the grounds that there would be no increased risk to either the
50
http://www.cngservices.co.uk/presentations-2/
http://www.chesterfieldbiogas.co.uk/index.php
52
http://www.cngservices.co.uk/assets/Press-Releases/October-5th-Press-Release-First-UK-Biogas-to-Grid-atDidcot.pdf
51
33 Draft VII 07/06/2012
gas consumers or to the public. The whole process, from the production of sewage to
injection of biomethane, takes around 23 days.
86. Another project that led to the injection of biomethane in the UK was at the Adnams
Brewery, Southwold. Adnams Bio Energy delivered the first biomethane produced from
brewery and food waste. The plant harnessed methane from malted barley and local
food waste. The gas produced was pumped into the national grid to heat around 235
homes. There are a few other UK BtG projects in the pipeline.
IGEM calls for more work looking into the feasibility of the ‘biomethane to grid’
(BtG) concept so as to identify principal learning points that can facilitate
widespread development of the associated technology. IGEM would like to see
biomethane being a big part of the UK government’s gas generation strategy.
IGEM understands that the maximum oxygen (O2) content in biomethane for
injection into the Gas Distribution Network (GDN) set under GS(M)R at 0.2% is
difficult for biomethane producers to meet. IGEM echoes one of the main
principal learning points from the Didcot project which is that the allowable
level of O2 detailed under GS(M)R needs a careful review in the context of
modern network conditions.
IGEM recognises that Wobbe number is a major issue because biomethane
injected into the Gas Distribution Network (GDN) must meet GS(M)R, which is
usually done by propane enrichment, hereby increasing the per unit cost of
biomethane post clean-up and decreasing the value of propane added. IGEM
encourages the use of comingling where possible by companies in order to
meet GS(M)R regulations.
4.4.4.5 What is IGEM doing?
87. Currently, IGEM is involved with the Ofgem review group looking into energy market
issues for biomethane projects (EMIB). The purpose of the EMIB review group is to
provide a platform for debate on the potential barriers to the commercial development of
biomethane projects within the energy market, as well as finding the appropriate means
of addressing such barriers. Some of the issues currently on the table for debate along
with corresponding recommendations are detailed below53:
88. The current GDN policies for connecting biomethane projects. The review
group considered whether the existing connections policies offered any barriers or
uncertainty to facilitating biomethane connections to the grid. At the moment, current
connection policy requires those connecting to the network to meet the full costs of all
53
http://www.gasgovernance.co.uk/sites/default/files/EMIB%20Report%20V0.1.pdf
34 Draft VII 07/06/2012
the work necessary to support the connection. In the context of biomethane entry, this
would involve the biomethane producer meeting the costs associated with developing the
entry facility as well as other investments associated with situations where there is
insufficient downstream demand to accommodate planned flows, such as compression,
to support a change in flow patterns with gas being moved upstream.
89. The review group recognised that enabling the GDNs to be responsible for providing
all aspects of the entry facility could prove to be a barrier to biomethane entry. As a
result, a minimum connection policy approached was agreed upon whereby the GDN
would undertake the minimum level of investment needed in order to comply with its
obligations. This, again, would require the GDN to specify the requirements that any
equipment installed at an entry point would have to meet.
90. Issues around the amount of biomethane going into the GDN system. The
review group recommended that entry capacity rights should be set out in the Network
Entry Agreement (NEA) for the relevant entry point. On the basis of steady flow for 365
days a year, the group accepted that the maximum capability that could be offered will
be equal to the minimum demand downstream of the entry point. In the instant where
the minimum demand is insufficient to accommodate biomethane, additional investment
may be able to increase capacity availability mainly in the form of compression such that
the gas can be moved upstream in an effort to address demand elsewhere of the GDN.
91. The review group also agreed that it would be appropriate for the entrant to bear
the costs of any such investment and recommended that Ofgem confirm that they would
expect it to be treated in the same way as other economically and efficiently incurred
network investment.
92. Existing standards for biomethane CV measurement, and the associated
governance regime. Dave Lander Consulting undertook some analysis to address this
issue. A summary of the full report can be found at Appendix 5 in the reference54.
93. Gas quality regulation. The review group reviewed the existing requirements for
gas quality to determine if they were fit for the injection of biomethane. The group
agreed that the requirements set out functional specification (document that covers
requirements for integrated biomethane to grid injection facility) was fit for purpose and
should be incorporated in the individual NEAs. The specification will initially be
maintained by the GDNOs but the group recommended that it becomes an IGEM
standard in the future.
54
http://www.gasgovernance.co.uk/sites/default/files/EMIB%20Report%20V0.1.pdf
35 Draft VII 07/06/2012
94. Data requirements and transmission. The review group reviewed the current
industry processes for transmitting flow/calorific value which were originally designed for
large offtakes. The group recommended that further work be undertaken to identify the
risks and benefits of alternative approaches for transmitting data.
95. IGEM are currently working with the GDNOs on a technical standard that will cover
the distribution of biogas and injection of biomethane into the GDN, which will include
the design, construction, inspection, testing, operation and maintenance of entry
facilities. There is conflicted interest between the biomethane producers who desire a
cheap method to measure properties in relatively small-scale plant, and networks who
desire accuracy by using expensive equipment for both gas quality control and fiscal
metering. Therefore, the standards will try to address the issues behind injection.
IGEM/TD/16 is the standard that will aim to cover the requirements for the
design, construction, inspection, testing, operation, and maintenance of the
entry facility used for the injection of biomethane into the Gas Distribution
Network (GDN).
96. Additionally, the proposed IGEM standard will cover the requirements for the design,
construction, inspection, testing, operation and maintenance of the different pipeline
types used for the distribution of biogas. Standards for biogas are very important as the
costs of cleaning up the gas, especially for small biogas producers such as farms, is
expensive. This is because the biogas from such facilities has a lot more impurities (see
paragraph 55) which make it imperative to select the right pipeline material and assess
how the chemical content of the gas could potentially impact on the chosen material.
IGEM understands that accurate monitoring of the composition of biomethane
entering the Gas Distribution Network (GDN) can be very expensive, however,
lessons from the Didcot prototype plant have identified that it is possible to
reduce costs significantly without causing any adverse effects to the integrity
of the network or consumers.
IGEM understands that biogas clean-up equipment is expensive per GJ of
product and that pipeline material selection for biogas produced from small
installations, such as plants located on small farms, is a pressing technical
issue. IGEM would work towards producing standards that outline the minimum
requirements for the odorisation and gas quality measurement equipment.
4.5 The biogas utilisation outlook
97. In the UK, the main sources of biogas include waste streams such as wastes from
sewage works. Most of the biogas produced has mostly been used to generate electricity
36 Draft VII 07/06/2012
due to the provision of cash incentives for the generation of low carbon or green
electricity i.e. the Renewables Obligation (RO)55 and the Feed-in Tariffs (FITs)56 scheme.
In August 2011, anaerobic digester (AD) plants were included in the range of
technologies that would be eligible for the FITs scheme, with tariffs paid on a plant
capacity basis. The FITs scheme currently provides 14p/kWh for installations up to
250kW and 13p/kWh for installations between 250 and 500kW.
98. On the heat generation side, the Renewable Heat Incentive (RHI)57 has incentivised
the use of biomethane for the generation of heat. Since its inception in November 2011,
the 1st phase of the RHI has provided the owners of renewable heat installations
commissioned since July 2009 a cash back subsidy for the first 20 years of use. This
offers an attractive reward for AD plant owners and guarantees a good return on initial
investment. The grant for AD-generated biomethane of all scales is currently at
7.1p/kWhtherm58. This, in turn, has increased appeal of using biomethane to generate
heat here in the UK and, hence, the number of biomethane to grid projects.
99. Another scheme, the Green Gas Certification Scheme (GGCS)59, has been introduced
as means of tracking the commercial transactions or contractual flows of biomethane (or
‘green gas’) through the supply chain. The scheme is open to anyone involved in the
biomethane supply chain; from producers who can register the gas they’ve injected to
the grid, to suppliers and other traders who register gas sale contracts they’ve agreed.
When final end-users of the gas purchase it, a Renewable Gas Guarantees of Origin
(RGGOs) is listed on the consumer’s certificate which acts as an identifier for each kWh
of gas purchased. This identifier contains information about where, when and how the
gas was produced which increases the attractiveness of using green gas to major endusers e.g. big supermarkets and other big organisations.
100.
Within
the
continent,
the
major
players
include
Sweden,
Germany
and
Switzerland. Sweden, for example, have gone down the transportation route mainly
because of 2 factors: one is the lack of a gas grid and the other is the low electricity
prices which forces biogas into areas other than the electricity market, therefore, there
are positive incentives available for the use of biogas as a vehicle fuel60. The use of
biogas as a vehicle fuel isn’t practical here in the UK because the vehicles are currently
more expensive to buy compared with petrol or diesel vehicles, and the filling stations
cost a lot more to build than conventional petrol stations. Biogas, however, could be
55
http://www.ofgem.gov.uk/Sustainability/Environment/RenewablObl/Pages/RenewablObl.aspx http://www.fitariffs.co.uk/FITs/
57
http://www.decc.gov.uk/assets/decc/What%20we%20do/UK%20energy%20supply/Energy%20mix/Renewab
le%20energy/policy/renewableheat/1387-renewable-heat-incentive.pdf
58
http://www.icax.co.uk/Renewable_Heat_Incentive.html
56
59
60
http://www.greengas.org.uk/pdf/ggcs-leaflet.pdf http://www.iea-biogas.net/_download/publications/workshop/7/06%20biogasupgrading.pdf
37 Draft VII 07/06/2012
used to run truck fleets but this cannot be done in isolation as demand will still not be
enough to accommodate the volumes of gas that could be produced.
101.
Germany is another example of a country that currently leads in terms of the
primary energy output produced from biogas. In 2009, Germany had 5000 fully
operational biogas plants with a combined electricity capacity of 1893MW. A further 1093
biogas plants are to be built before the end of 2012, adding an extra 516MW of electrical
capacity. Germany’s positive outlook to biogas is largely down to the legal framework
provided by the German renewable energies law (EEG)61.
102.
The law, first passed in 2000 and amended in 2004 and 2009, implements the EU
Directive on the Promotion of Renewable Energies - which sets ambitious targets for
renewable energies in the EU. The EEG is very pro-renewable energy in that it mandates
the grid operators to pay a government-specified feed-in-tariff to the energy generators
supplying energy to the grid from renewable sources. It also provides a 20-year
guarantee on remuneration rates and add-on premiums if innovative technology is used,
for example using manure for biogas production62. This acts as an incentive for
biomethane suppliers as they are given priority to the grid and the responsibility for a
major part of the associated costs of biomethane injection is transferred to the grid
operators. This has resulted in a growth in the area of biomethane injection.
103.
However, the German biogas industry struggled between 2007 and 2008. This
was due to a number of reasons which included the adoption of corn silage by many of
the plants as feedstock, and the fact that many of the plants were used only for
electricity production, wasting the heat produced. This led to economic problems up until
2009 when the new legislation was updated and implemented. Since the 1st of January
2009, the basic rate applied to biomethane (excluding biomethane produced from
wastewater plant) has been €0.1167/kWh (£0.098/kWh) for installation capacities of
150kW or below. This rate drops to €0.0918/kWh (£0.077/kWh) for up to 500 kilowatts,
€0.0825/kWh (£0.069/kWh) for up to 5MW and €0.0779/kWh (£0.065/kWh) for up to 20
MW63.
61
http://www.german-biogas-industry.com/in-detail/from-germany-to-the-far-corners-of-the-world-biogas-isin-high-demand/
62
http://www.eurobserv-er.org/pdf/baro200b.pdf
63
http://www.eurobserv-er.org/pdf/baro200b.pdf
38 Draft VII 07/06/2012
Figure 19: Biogas production in Germany between 2000 and 200964
104.
Research carried out by the German biomass research centre puts the potential
for Germany’s biomethane output at between 11.5 and 13.9 million tonnes of oil
equivalent (mtoe) per annum compared to the annual natural gas consumption of 76.6
mtoe per annum. In effect, Germany can reduce its dependency on natural gas imports
by one-sixth by tapping into biomethane. Unlike Germany, the UK has not so far opted
for AD biogas from energy crops and has preferred to rely on energy recovery from
landfill gas (LFG). According to the Department for Energy and Climate Change (DECC),
1723 ktoe of biogas was produced in 2009, of which 1474.4 ktoe was landfill biogas
(about 85%).
5
Bio-SNG
105.
The gasification of coal provided a much cleaner and sustainable way of utilising
the resource when it was first introduced, offering a more versatile form of the energy
source. The process converts coal into a gaseous fuel, known as syngas, retaining most
of its useful energy and can be readily purified and transported/distributed. Coal
gasification also offers a number of advantages over the conventional combustion of coal
which include eliminating the difficulty of handling large quantities of the material at
customers’ premises. As well as coal, biomass can be used to produce SNG which could
be advantageous from an emissions point of view. Other forms of feedstock include fossil
and solid waste.
64
http://www.ahk-balt.org/fileadmin/ahk_baltikum/Projekte/Erneuerbare_Energien/Biogas_Use_Mauky_01.pdf
39 Draft VII 07/06/2012
106.
Several products can be produced from gasification; ‘Old fashioned’ towns gas
and various industrial fuel gases can be produced, as well as substitute natural gas or
synthetic natural gas (SNG) for gas-grid purposes. The product, SNG, is such that it is
fully interchangeable with natural gas without the need of further conversion
downstream.
107.
SNG produced by the gasification of any type of biomass is known as bio-SNG.
Bio-SNG can be used in a similar way to biomethane generated via anaerobic digestion
with the added advantage that the production can accommodate a much wider range of
input biomass feedstocks, not commonly suitable for AD, including woody biomass (this
is usually subject to the gasifier type used). This is also the reason why bio-SNG is
believed in some quarters to be crucial to the use of renewable gas to achieve large
reductions in greenhouse gas emissions past 2050. The argument is that biomethane
produced by AD is a limited resource because of the feedstock inflexibility. A consultation
report, prepared by Progressive Energy Ltd and CNG Services, on the feasibility of bioSNG for National Grid, Centrica and NEPIC, reports that for bio-SNG the majority of the
mass and energy flow produce the product gas rather than just the biodegradable
fraction (as is the case with biomethane). This effectively means the gasification route to
renewable or bio-SNG has higher conversion efficiencies and can be executed on a more
substantial scale65, with plant sizes of the order of 100,000-1,000,000 tpa (as compared
to AD capacities of 10,000-100,000 tpa).
5.1 Bio-SNG production using gasifiers
108.
The process and technology for bio-SNG production is similar to that required for
the production of SNG from coal. A wide range of gasifier types are be available, all of
which can be categorised into two main types: dry ash gasifiers and slagging gasifiers.
The ash formed from the gasification of any hydrocarbon fuel is thermoplastic i.e. it
doesn’t turn from solid to liquid at a single phase change temeperature. Operating the
gasifier between 850°C and 1000°C produces predominantly dry ash at the bottom of
the vessel while operating between 1400°C and 2000°C produces ash that is melted to a
liquid slag with relatively low viscosity at the bottom. The key difference between the
two types of gasifiers with respect to waste and coal, which are both ‘dirty’ fuels, is
where all the heavy metals, minerals and all other contaminants present end up. In a
dry ash gasifier using waste or coal, all the contaminants end up in the ash posing a
disposal problem. If the ash is land-filled, heavy metals are leachable in solution out of
65
Bio-SNG. Feasibility Study. Establishment of a regional Project. Progressive Energy & CNG Services,
November 2010.
40 Draft VII 07/06/2012
landfill as rainwater percolates through it. In a slagging gasifier, the heavy metals are
vitrified in the resulting product and cannot be leached out66.
109.
Gasifiers can also be air blown or oxygen blown. The decision to go with either,
for the most part, is usually based on the economics of the proposed plant and the final
end-use of the gas. The majority of dry ash gasifiers used to process biomass are air
blown. This is because such plants are usually small scale, low pressure and temperature
plants with relatively low thermodynamic efficiencies. This also means that the syngas
produced contains lots of nitrogen (N2). In an oxygen blown gasifier, pure oxygen is
injected in the vessel along with the steam producing a syngas that doesn’t have a high
percentage of inert nitrogen gas and therefore has a high calorific value. As a result,
such plants are large scale with high thermodynamic efficiencies. Other advantages of
using oxygen blown slagging gasifiers to process biomass include:
 Typical high plant pressure which means process vessels can be smaller
 Solubility of the product gases are higher which is an advantage when the gases are
cleaned-up
 There is less compression needed if the bio-SNG is to be injected in the NTS (because
they are usually large scale plants operated at high pressure)
Figure 20: A schematic diagram of the British Gas Lurgi slagging-bed-gasifier67
66
http://www.ihpa.info/docs/library/reports/Pops/June2009/DEF3SBCWASTEGAS_090808_.pdf
41 Draft VII 07/06/2012
110.
The product gas leaving the slagging gasifier is usually quenched and cooled to
remove tar, oil and liquor, leaving a gas that contains mainly carbon monoxide (CO) and
hydrogen (H2) in a ratio of about 2:1. There is also a subtantial amount of methane in
the stream together with other sulphur compounds such as H2S, Carbonyl sulphide
(COS) and carbon disuphide (CS2). For SNG production, the remaining gases are
chemically processed in reaction process known as methanation. The final products from
this stage including steam, methane and carbion dioxide, are then separated. The
stream is cooled to remove steam while CO2 is extracted using commercially available
processes to leave CH4 as the only product. Figure 21 shows an overview of the bio-SNG
production process.
Figure 21: Overview of the bio-SNG production process
111.
Bio-SNG production from biomass mixes and waste have been tested at small to
medium scale. A 1MW SNG demonstration plant has been built in Gussing, Austria for
the complete process demonstration from woody biomass to SNG. A much bigger
200MW biomass gasification plant is to be built in Sweden from 2013 under the E.ON
Bio2G project.
112.
The bio-SNG fuel can be integrated into the existing energy system in the same
way as natural gas or biogas (usually as processed biomethane), either for use in
vehicles or injection into the NTS. To meet the specifications required for gas utilisation
in vehicles or gas injection into the existing natural gas infrastructure, the produced bioSNG will need to be further processed (this is much the same as AD gas processing).
67
B. Buttker, R. Giering, U. Schlotter, B. Himmelreich, K.Wittstock, Full Scale Industrial Recovery trials of
shredder residue in a high temperature slagging-bed-gasifier in Germany, SVZ report, pp. 7.
42 Draft VII 07/06/2012
113.
Although proven technically feasible, the bio-SNG option is not as widespread as
other renewable options for gas. In the UK, bio-SNG needs to be considered because of
the potential benefits it can offer. Some of the recognised benefits of this option include:
 High process speed for conversion of feedstock to energy (process speed is of the
order of hours)
 Potential to execute on a gas-grid scale at cost-competitive capital per GWtherm of
energy input
 Versatile/flexible
fuel/feedstock
types
which
include
dry
solid
fuel,
municipal
commercial and industrial wastes, woody and contaminated biomass, coal, petcoke,
plastics,
sewage
sludge,
solvents,
inks,
bio
hazardous/chemical/genetic
wastes,
persistent organic pollutants, landfill and slag tip mined material, etc.
 High process efficiency (77% for BGL Oxygen-blown gasifier)
 Potential to reuse waste produced from the process as an environmentally friendly
construction material or fracking material
 Potential to capture CO2 using highly efficient post-methanation technologies
IGEM welcomes the development and use of bio-SNG as a renewable gas option
due to the potential benefits it offers in terms of process speeds, feedstock
flexibility and reusable wastes (or recyclates). IGEM sees bio-SNG as a long
term interchangeable option to North Sea natural gas that can ensure the
future of the gas industry for generations to come.
IGEM encourages more investment into the bio-SNG concept and the associated
technologies to demonstrate its feasibility to policy makers and the wider
public. IGEM would like to see bio-SNG embedded in future energy policies
relating to the use of renewable gas here in the UK.
6
Summary of conclusions
IGEM understands that the use of life-cycle-analysis (LCA) at present is
controversial because there is still no globally accepted standard way of
performing LCA calculations. IGEM understands that the main issue with this
technique is that of ‘how far back down the biofuel chain do you go’ in the
calculation process in terms of what is included or excluded (e.g. fertilisers
used to grow feedstock, energy used during the mining process of the minerals
used to manufacture fertilisers, etc).
IGEM,
however,
understands
great
strides
are
being
made
by
the
Intergovernmental Panel on Climate Change (IPCC) to come to a global
agreement on LCAs.
43 Draft VII 07/06/2012
IGEM understands that sourcing biofuels sustainably is important if it is to
command a major share of the UK energy mix. IGEM, however, believes this
cannot happen unless there is some sort of sustainably certified supply chain
that encompasses the feedstock needs of all the different individual biofuel
interest areas.
IGEM welcomes the increasing UK interest in 2nd generation biofuels including
more novel feedstock options such as algae and waste-derived supplies. IGEM
believes that biofuels sourced from organic waste, are not only more
environmentally favourable and cheaper to source than biofuels grown from
energy crops, but can also go a long way to ensuring this energy option starts
to effectively compete both economically and environmentally with other
renewable options.
IGEM believes using the anaerobic digestion route (AD) to treat waste, with the
potential to provide energy at the same time, has an important role to play as a
means of avoiding the emission of greenhouse gases (GHGs) from landfill
disposal, some of which are 20 times more potent as a GHG than carbon dioxide
(CO2).
IGEM calls for more work looking into the feasibility of the ‘biomethane to grid’
(BtG) concept so as to identify principal learning points that can facilitate
widespread development of the associated technology. IGEM would like to see
biomethane being a big part of the UK government’s gas generation strategy.
IGEM understands that the maximum oxygen (O2) content in biomethane for
injection into the Gas Distribution Network (GDN) set under GS(M)R at 0.2% is
difficult for biomethane producers to meet. IGEM echoes one of the main
principal learning points from the Didcot project which is that the allowable
level of O2 detailed under GS(M)R needs a careful review in the context of
modern network conditions.
IGEM recognises that Wobbe number is a major issue because biomethane
injected into the Gas Distribution Network (GDN) must meet GS(M)R, which is
usually done by propane enrichment, hereby increasing the per unit cost of
biomethane post clean-up and decreasing the value of the propane added.
IGEM encourages the use of comingling where possible by companies in order
to meet GS(M)R regulations.
IGEM/TD/16 is the standard that will aim to cover the requirements for the
design, construction, inspection, testing, operation, and maintenance of the
44 Draft VII 07/06/2012
entry facility used for the injection of biomethane into the Gas Distribution
Network (GDN).
IGEM understands that accurate monitoring of the composition of biomethane
entering the Gas Distribution Network (GDN) can be very expensive, however,
lessons from the Didcot prototype plant have identified that it is possible to
reduce costs significantly without causing any adverse effects to the integrity
of the network or consumers.
IGEM understands that biogas clean-up equipment is expensive per GJ of
product and that pipeline material selection for biogas produced from small
installations, such as plants located on small farms, is a pressing technical
issue. IGEM would work towards producing standards that outline the minimum
requirements of planting, odorisation and gas quality measurement equipment.
IGEM welcomes the development and use of bio-SNG as a renewable gas option
due to the potential benefits it offers in terms of process speeds, feedstock
flexibility and reusable wastes (or recyclates). IGEM sees bio-SNG as a long
term interchangeable option to North Sea natural gas that can ensure the
future of the gas industry for generations to come.
IGEM encourages more investment into the bio-SNG concept and the associated
technologies to demonstrate its feasibility to policy makers and the wider
public. IGEM would like to see bio-SNG embedded in future energy policies
relating to the use of renewable gas here in the UK.
7
Acknowledgements
IGEM would like to thank the following for providing interviews and providing
assistance.
Laszlo Mathe - Bioenergy coordinator at WWF International
John Baldwin - CNG Services Ltd
Chris Hodrien - Technical consultant at Timmins CCS and lecturer at Warwick University
Anthony Day - Independent Consultant
Please direct all queries or comments to:
[email protected]
+44 (0) 844 375 4436
45 Draft VII 07/06/2012
8
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