Biofuels final report - IGEM · 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

Draft VII 07/06/2012

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Copyright © 2011, IGEM. All rights reserved Registered charity number 214001 All content in this publication is, unless stated otherwise, the property of IGEM. Copyright laws protect this publication. Reproduction or retransmission in whole or in part, in any manner, without the prior written consent of the copyright holder, is a violation of copyright law. Published by the Institution of Gas Engineers and Managers


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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

Organisation

UNESCO

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 Introduction to biofuels 7

1.1 What are the main drivers behind biofuels? 9

1.2 What are the potential impacts of using biofuels? 10

1.2.1 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

2 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

3 Biofuels used for transport – a UK perspective 20

3.1 Types of feedstock 21

3.1.1 Sources of biofuel to the UK 21

3.2 Companies in the UK making bioethanol and biodiesel 21

4 Biogas 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 Biogas cleaning methods 26

4.4 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 The biogas utilisation outlook 36

5 Bio-SNG 39

5.1 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/


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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 http://www.official-documents.gov.uk/document/other/9780108508868/9780108508868.pdf 3 http://www.safnw.com/2011/05/photo-captions/


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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 Specific biofuel Production process

Bioethanol Cellulosic ethanol Advanced enzymatic hydrolysis

and fermentation

Synthetic

biofuels

Biomass-to-liquids (BTL)

Fischer-Tropsch (FT) diesel

Biomethanol

Heavier alcohols (butanol and mixed)

Dimethyl ether (DME)

Gasification and synthesis

Biogas Bio-synthetic natural gas (SNG)

Bio-methane

Gasification and synthesis*

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 legally-

binding 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 http://www.iea.org/papers/2008/2nd_Biofuel_Gen.pdf 5 http://www.eubia.org/107.0.html 6 http://www.iea.org/papers/2011/biofuels_roadmap.pdf


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consumed in the same period, recorded at 5074 billion litres, puts the global production

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 life-

cycle. 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

M

toe (

millio

n t

on

nes

of

oil e

qu

ivale

nt)


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Environmental Social & economic impacts

Technical issues

Loss of biodiversity

x x

Stress on water x x Land-use x x

Atmospheric pollution

x x

Cost effectiveness x x Energy usage 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


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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/ 10 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.


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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-cycle-

assessments (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 14 IGEM interview with Chris Hodrien, technical consultant at Timmins CCS and lecturer at the University of Warwick


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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.


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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 17http://www.unido.org/fileadmin/user_media/UNIDO_Header_Site/Subsites/Green_Industry_Asia_Conference__Maanila_/GC13/Gallagher_Report.pdf


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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


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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 pre-

treatment 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 pre-

treatment 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 http://www.wgbn.wisc.edu/producers/biomass-sources 20 http://www.ieabcc.nl/publications/t32.pdf


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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 22 http://www.wpi.edu/Pubs/E-project/Available/E-project-042810-165653/unrestricted/Ethanol_from_Sugar_Beets_-_A_Process_and_Economic_Analysis.pdf


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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 http://www.meadmadecomplicated.org/science/fermentation.html 24 http://www.esru.strath.ac.uk/EandE/Web_sites/02-03/biofuels/what_biodiesel.htm


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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 http://kenknee.blogdrive.com/ 26 http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2009:140:0016:0062:en:PDF 27 http://www.ukpia.com/industry_issues/fuels/biofuels-and-alternative-fuels.aspx 28 http://assets.dft.gov.uk/statistics/releases/biofuels_april_2011/rtfoaug2011.pdf 29 http://www.tycofis.co.uk/bio-diesel/joint-statement-on-biofuel.pdf


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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).

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

Corn34%

Wheat23%

Sugar cane21%

Sugar beet15%

Molasses3% Other

4%

Used cooking

oil50%

Soy25%

Oil11%

Tallow6%

Palm4%

Unknown4%

Figure 10: Bioethanol feedstock

Figure 11: Biodiesel feedstock


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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


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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 gas-

producing 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 by-

product.

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 33 http://www.hydrocarbonprocessing.com/Article/3010578/Refining-Biofuels/BP-to-start-up-Hull-biorefinery-in-UK-later-this-year.html


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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 http://www.biogas-info.co.uk/index.php/types-of-ad.html 35 http://www.biogas-info.co.uk/index.php/types-of-ad.html


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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

pharmaceuticals. Farm gas also has high NH3 content37.

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 37 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.


26

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


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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


28

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 http://www.iea-biogas.net/_download/publi-task37/upgrading_report_final.pdf 42 http://www.aebiom.org/IMG/pdf/Nielsen_text.pdf


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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


30

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 http://www.cngservices.co.uk/presentations-2/ 45 http://cnch4.com/mediadetails.php?ID=19


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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

dewpoints

The gas shall not contain solids or liquids

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


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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/ 49http://www.decc.gov.uk/assets/decc/what%20we%20do/uk%20energy%20supply/energy%20markets/gas_markets/nonconventional/1_20091229125543_e_@@_biomethaneguidance.pdf


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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/ 51 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-at-Didcot.pdf


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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


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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


36

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


37

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 end-

users 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 56 http://www.fitariffs.co.uk/FITs/ 57http://www.decc.gov.uk/assets/decc/What%20we%20do/UK%20energy%20supply/Energy%20mix/Renewable%20energy/policy/renewableheat/1387-renewable-heat-incentive.pdf 58 http://www.icax.co.uk/Renewable_Heat_Incentive.html 59 http://www.greengas.org.uk/pdf/ggcs-leaflet.pdf 60 http://www.iea-biogas.net/_download/publications/workshop/7/06%20biogasupgrading.pdf


38

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-is-in-high-demand/ 62 http://www.eurobserv-er.org/pdf/baro200b.pdf 63 http://www.eurobserv-er.org/pdf/baro200b.pdf


39

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


40

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 bio-

SNG 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.


41

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


42

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 bio-

SNG 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.


43

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.


44

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


45

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


46

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Documents

Biofuels final report - IGEM · 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