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Bio-SNG
Feasibility Study.
Establishment of a
Regional Project
Progressive Energy &
CNG Services
Clients: NEPICNational GridCentrica
Date:10/11/10
Issue:Vs 2.3
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Document Control Record
Document Title: Final Report
Issue 2.3
Date Issue: 10/11/10
Project Title: Bio-SNG: Feasibility Study, Establishment of a Regional Project
Prepared by: Phillip Cozens & Chris Manson-Whitton
Clients NEPIC, National Grid and Centrica
Amendment Record
Issue Date of Issue Notes
0.1 29/09/10 Executive summary for comment
1.0 25/10/10 Internal review
2.0 28/10/10 Issued
2.1 29/10/10 Minor adjustments
2.2 01/11/10 Adjustment to Footers
2.3 10/11/10 Minor corrections following feedback
Because this work includes for the assessment of a number of phenomena which are unquantifiable, the
judgements drawn in the report are offered as informed opinion. Accordingly Progressive Energy Ltd.gives no undertaking or warrantee with respect to any losses or liabilities incurred by the use of
information contained therein.
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Contents
1 Executive Summary ...............................................................................................................................4
2 Introduction .......................................................................................................................................... 143 Review of the fiscal, legislative and regulatory regime ....................................................................... 16
3.1 Renewable Energy Incentives and Instruments ......................................................................... 163.2 Energy from Waste regulations and Issues ................................................................................ 183.3 Emissions Trading ...................................................................................................................... 193.4 The Gas Safety Management Regulations ................................................................................ 203.5 Other key regulations ................................................................................................................. 20
4 Feedstock ............................................................................................................................................ 21
4.1 The significance of Bio-SNG in the energy scene ...................................................................... 214.2 Pure Biomass resources........................................................................................................... 224.3 Properties of pure biomass fuels.............................................................................................. 244.4 Waste materials .......................................................................................................................... 254.5 Total amount of Biomass resource for Bio-SNG production ...................................................... 284.6 Commercial considerations for pure biomass........................................................................... 284.7 Commercial considerations for wastes ....................................................................................... 294.8 Feedstock Conclusions .............................................................................................................. 31
5 Process and Technology Review ........................................................................................................ 32
5.1 Biomass reception, preparation and handling. ........................................................................... 325.2 Gasification ................................................................................................................................. 335.3 Gas Processing .......................................................................................................................... 395.4 Methanation ................................................................................................................................ 415.5 Gas conditioning, compression and metering ............................................................................ 425.6 Conclusions on Process and Technology .................................................................................. 43
6 Economic Assessment ........................................................................................................................ 44
6.1.1 Scale and operational assumptions........................................................................................ 446.1.2 Investment Cost assumptions ................................................................................................ 456.1.3 Operating Cost assumptions .................................................................................................. 486.1.4 Feedstock ............................................................................................................................... 486.1.5 Revenue Assumptions ............................................................................................................ 50
6.2 Levelised Cost analysis .............................................................................................................. 506.3 Sensitivity Analysis ..................................................................................................................... 54
6.3.1 Escalation ............................................................................................................................... 556.3.2 Impact of capital Cost, Opex, Fuel price, RHI and heat sales ................................................ 566.3.3 Comparison with an SRF fuelled electricity project ................................................................ 57
6.4 Financial conclusions ................................................................................................................. 587 Lifecycle carbon emissions and Cost of Carbon Analyses compared with alternatives ..................... 60
7.1 Lifecycle carbon emissions ......................................................................................................... 607.2 Cost of carbon abatement via Bio-SNG ..................................................................................... 64
8 Risk Assessment and Financing Considerations ................................................................................ 69
8.1 Conclusions from risk assessment and financing considerations .............................................. 749 Preliminary Scoping of a lead, beacon project .................................................................................... 75
9.1 Beacon Project configuration options ......................................................................................... 759.2 Location: The North East ............................................................................................................ 779.3 Site analysis................................................................................................................................ 789.4 Regional Feedstock .................................................................................................................... 83
10 Conclusions ......................................................................................................................................... 84
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1 Executive Summary
Methane is an attractive heat and transport fuel vector. It is a clean and relatively low carbon intensity
fuel. It can be utilised efficiently and has established infrastructure and demand-side technologies (gas
boilers for heating and an increasingly wide range of available CNG vehicles). The UK has one of the
most extensive gas networks in the world. Bio-methane retains all the attributes of natural gas, with the
crucial advantage that the fuel is renewable, offering substantial Carbon Dioxide savings. Few other
renewable vectors are as fungible, with so few demand-side constraints. Biomethane can, and is being
produced via the upgrading of biogas from Anaerobic Digestion. However, in order to achieve a step
change in production capacity, alternative approaches such as via thermal routes (termed Bio -SNG) are
necessary. Whilst technically feasible, this approach is less mature than anaerobic digestion. Transition
from aspiration, to widespread operating facilities and infrastructure requires a detailed understanding of
the technical and commercial attributes of the full chain from feedstock supply through to delivery of grid
quality gas, as well as the development of the first crucial operating facility which provides the tangible
proof of concept for roll out. The chemical and processing industrial heritage in the North East, its natural
gas and services infrastructure and its track record of innovation make it an attractive region to locate
such a project.
This report provides a critical appraisal of the opportunity afforded by Bio-SNG, building on a review ofthe issues associated with biomass sourcing, a detailed analysis of the technology options and
applicability for injection into the UK grid, as well as a financial appraisal. It draws on benchmarking data
to demonstrate the full lifecycle carbon dioxide savings and also demonstrates that the Bio-SNG route is
a very cost effective route for decarbonisation compared with other renewables. It provides proposals for
implementation pathways, specifically how a Bio-SNG demonstration could be established in the North
East.
Regulatory Position
Implementation of Bio-SNG will only take place with the appropriate tax, incentive and legislativeenvironment. Therefore it is critically important to establish the position that is pertinent to Bio-SNG
production on its own account, but also in comparison with the situation for other competitive users of
biogenic energy resources. The Renewable Obligation is most established instrument in the UK to
incentivise the use of biogenic resource, in this case for provision of electricity. In order to facilitate
expansion of renewable heat and Bio-SNG in particular, the forthcoming Renewable Heat Incentive must
be structured such that such projects are commercially attractive compared with electricity production.
In addition to the incentives structures, the regulatory environment must be clear and appropriate,
particularly with regard to: requirements for gas injection, emissions directives, and how the use of waste
as a feedstock is treated.
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Feedstock
In contemplating the use of biomass for the production of Bio-SNG it must be appreciated that there are
competing uses for biomass in many industrial sectors building materials, chemicals, heating, electricity
generation, and transport bio-fuels. Estimates vary widely on the potential for the production and trading
of biomass fuels but government incentives for non-fossil energy are fuelling a growing demand, globally.
Global capacity for the production of bio-fuels has been estimated at 180EJ1per annum a figure which is
only 18 times the UK total energy consumption of 10EJ/annum. The estimates of potential indigenous
biomass production vary, but range up to a figure of 60PJ/a2of conventional woodfuels, and in the future
a further 60PJ, or more from energy crops3. The UK waste streams also represent a considerable
potential biomass resource of the order of 300PJ. The UK gas consumption is around 4EJ per annum of
which approximately 30% is associated with domestic heating. Combinations of imported and indigenous
biomass together with waste-derived materials have the potential, therefore to make a significant
contribution to the overall domestic heating gas load.
Major users of biomass fuels are making strategic moves upstream in the biomass supply chain to secure
positions that will support the long term viability of their power sector investments. It follows that
investment in Bio-SNG facilities will undoubtedly require similar initiatives by their owners or developers.
In evaluating the merit of investment in biomass power it is important to take into account the global
market influence created by a variety of government backed incentive schemes that promote biomass
power plant developments throughout the world.
From a technical perspective biomass fuels are generally less well understood than coal, and the
technologies that use biomass fuels are less well developed. Hence it is particularly important to
understand the properties of candidate biomass fuels in undertaking process design and specification,
especially with respect to fuel preparation and handling and gasifier operations. Standards do exist for
solid biofuels of all types, the EU has developed via CEN/335 a comprehensive approach to the
classification and standardisation of solid bio-fuels and this should be used in transactions between sellerand buyer and by process designers in order to assure reliable and certifiable operational conditions.
Waste materials represent a significant bio-energy resource, however, it should not be assumed that they
are readily available for use in energy applications. Much of the UK waste stream is under long term
disposal contracts with local authorities, however, commercial and industrial wastes are unlikely to be on
long term disposal contracts and are, in principle a potential resource. As for clean biomass, it is
necessary to go upstream in the supply chain to secure reliable supplies of suitable materials. In
common with the standardisation of solid bio-fuels, similar standards and classifications exist under
1
1 Exajoule = 1018
Joules21 Petajoule = 10
15Joules
3 Some estimates consider 550PJ of energy crops per annum a possibility, although this would require seismic
change in land usage and appropriate commercial drivers.
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CEN/343 for the production of Solid Recovered Fuels (SRF) which too can be used to facilitate trade
between buyer and seller and to inform process design.
In summary, it is likely that the development of Bio-SNG facilities will require the developer to go
upstream into the supply chain for both grown and waste derived fuels, however, specification and quality
control are vital determinants of project success.
Process and technology
The process technology review establishes that, in principle, the major process operations required to
produce Bio-SNG can be identified and assembled from existing technology suppliers. This does not
mean that a Bio-SNG development would be free from technical risk, but it does mean that there is no
fundamental process development required to create a viable Bio-SNG platform.
The essential first condition that must be satisfied is that feedstock specification and the process design
are matched; the gasifier in particular can not be omnivorous.
From a wide range of possible gasifier types the review closes in on the choice of oxygen blown direct
bubbling fluidised bed, either pressurised or un-pressurised. The choice of bubbling fluidised bed is
informed by commercial analysis which shows the importance of waste-derived fuels. The fluidised bed
is capable of accepting both pure biomass and waste derived fuels, in contrast to the alternative entrainedflow gasifiers. Indirect fluidised bed gasifiers give a significant and beneficial direct conversion to
methane in the gasifier, reducing therefore the process losses incurred in making SNG from synthesis
gas, as well as the potential to operate using air and/or steam rather than oxygen as an oxidant.
However, indirect gasifiers are less well developed and do risk the leakage of significant quantities of
nitrogen into the syngas, which in turn will reduce the CV and Wobbe index of the resulting SNG.
Achievement of pipeline gas quality has been taken as an indispensable condition. The indirect gasifiers
can give a level of methane in syngas in excess of 10%, however, for example, the High Temperature
Winkler direct fluidised bed can give in excess of 5% methane in syngas. This level of methane content
still gives reasonable conversion efficiencies to Bio-SNG of at least 65%. In view of the relative immaturity
of the technology and the risk of nitrogen migration the benefits of the indirect fluidised bed gasifiers are
considered to be marginal. This viewpoint is further enhanced if the heat output from the plant is
valorised by the 2 ROC electricity regime or where possible as renewable heat under the RHI; with
optimisation of the process design, the associated electricity and potential heat sales are likely at least to
compensate for any small loss of conversion efficiency to Bio-SNG.
Downstream of the gasifier the gas processing operations are conventional technology: heat recovery
and power generation, gas scrubbing, water gas shift, methanation, conditioning and compression. (The
water gas shift reaction is required to adjust the molar ratios of carbon monoxide and hydrogen in the
syngas to the ideal conditions for methanation.) Whilst these processing elements are all conventional,
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they are critical for ensuring pipeline quality gas. In general the GS(M)R specification should be attainable
by this process route, although the tight limit on hydrogen content may demand a higher gas recycle
through the methanation phase than would otherwise be required, and the stringent dewpoint
specification imposes drying requirements in light of the high moisture from the methanation reactor.
These investigations do not identify the optimisedprocess configuration regarding energy consumption.
There is a balance to be struck between gasifier operating pressure, gas train pressures and
compression loads and the power consumption for Bio-SNG export. This should be undertaken in
conceptual design where more detailed information from equipment suppliers is required.
Financial Analysis
Two representative scales of facility are analysed at 50MWth and 300MWth input. These would produce
approximately 230GWh and 1400GWh of Bio-SNG per annum based on the assumed process
efficiencies. This represents sufficient gas for approximately 15-100,000 households or 25,000-150,000
passenger vehicles. Three of the larger facilities would supply 1% of the UK domestic gas market.
Dependent on the fuel type these facilities would require between 75-100,000 te pa of feedstock at the
small scale and 450-600,000 te pa at the large scale. With increasing scale, the challenges associated
with contracting sufficient fuel for the duration of the financing period of a plant increase.
The feedstock price is assumed to be 7/GJ for imported wood pellets, 5/GJ for a mix of imported and
indigenous woodchip and -1.50/GJ for processed Solid Recovered Fuel from mixed waste streams. The
woodfuel prices are 2010 figures, based on biomass prices for large scale electrical generation plants,
taken from the technical annexes issued by DECC in the February 2010 RHI review4. The waste fuel
price is based on industry knowledge of SRF produced by Mechanical Biological Treatment with a
biogenic energy content of ~60%.
Using the investment5and operational cost assumptions derived, the levelised cost of Bio-SNG in 2010
prices has been shown to range between 67-103/MWh for the small scale facility and 32-73/MWh for
the large scale facility dependent on the type feedstock used, with the waste based fuel being the
cheapest. Assuming the RHI at 40/MWh of biogenic fraction this equates to out turn gas prices of 43-
65/MWh at small scale and 8-33/MWh at the large scale. In conventional gas units, this analysis
suggests an out turn gas price of 123-185p/therm at small scale and at large scale 24, 63 and 96p/therm
for SRF, Woodchip and pellet feedstock respectively.
4Biomass prices in the heat and electricity sectors in the UK, Department of Energy and Climate Change
(January 2010)565-75Million for the small facility and 215-250Million for the large facility, depending on feedstock type.
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Comparing these figures with a central case of 59p/therm gas (DECC6) shows that with the proposed
incentive regime, a large SRF fuelled facility has the potential to provide gas effectively, as could a facility
fuelled by a mix of SRF and biomass. At this scale, a mix of indigenously sourced woodchip and imported
woodchip might be competitive, but a facility fuelled by wood pellet is unlikely to be able to compete and
would need an increase of at least 15/MWh to the RHI to enable it to compete. At the smaller scale, Bio-
SNG cannot be supplied competitively from any fuel. For a competitive demonstration facility at this scale,
the RHI would need to be increased by a further ~40/MWh, or else a capital grant of ~40M would be
necessary.
For the large scale facility operating on woodchip, a sensitivity analysis indicates that a change in capital
cost of 30% equates to a change in outturn Bio-SNG price of 35%. A 1.5/GJ change in biomass price
(30%) equates to nearly a 40% change in outturn Bio-SNG price. This implies for example that volatility ininternational biomass shipping costs alone could readily effect a change of 0.5/GJ (6.5/te) on feedstock
and therefore 13% on Bio-SNG price. This particular sensitivity to biomass price represents a major risk
onwards for the life of the plant depending on the contracting basis. Conversely, whilst capital cost is an
important factor, the capital cost is fixed at financial close, so does not represent an ongoing risk to the
project.
Looking to the future, gas prices will increase, but it is contended that biomass prices are likely to
escalate broadly in line with raw energy costs due to both increased international demand for renewable
feedstocks, but also simply because of the displaced cost of energy (the only perturbation on this would
be a significant increase in the price of carbon, although natural gas is a relatively low carbon feedstock).
In isolation this would result in a somewhat increased competitive position for Bio-SNG since the fuel cost
is only a component of the total levelised cost. However, the extent of this effect will be ameliorated by
any increase in capital and operational costs over and above inflation due to both increases in energy
costsper se, and also supply/demand pressure for renewable energy.
A first of a kind, large scale Bio-SNG production facility from SRF is likely to be challenging to finance and
represents a substantial quantum of investment, yet this analysis indicates that scale is necessary to
provide an acceptable cost base. Therefore an alternative pathway is likely to be necessary. One route is
to find a more commercially attractive basis to develop a syngas platform, from which a slip stream of Bio-
SNG production could be established.
By comparison, a 50MWth gasification plant configured to produce 13MWe using an SRF feedstock and
supported by two ROCS under the RO is morelikely to be viable. Because such a case is still predicated
on some of the fundamental technical principles necessary for Bio-SNG production, it does not provide a
particularly attractive return, but might be an alternative pathway to demonstrating Bio-SNG production
using a slipstream from an otherwise commercially viable plant, therefore limiting the level of additional
6Energy and emissions projections, DECC (June 2010) Annex F
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Domestic Ground source heat pumps using grid electricity indicate 5500 cost per tonne of carbon
abated compared with natural gas using the recent EST report for a mid range installed unit, and over
850 when compared with oil. When using renewable electricity (2 ROC supported offshore wind) the
costs of CO2e abatement are ~460/te and 360/te respectively. Again on this basis, Bio-SNG competes
very effectively. If the adoption of electrical based solutions demands more grid reinforcement than would
be required to the gas network by Bio-SNG solutions, then the differential in cost per tonne of carbon
abated is likely to be even greater.
For transport applications, Bio-SNG is also significantly more cost effective than electrical solutions
(either using grid electricity - 1000/ te CO2e, or presuming hypothecated offshore wind derived
renewable electricity - 600/ te CO2e). However, this analysis does suggest that whilst Bio-SNG does
offer significant carbon savings for the transport sector, on a cost per tonne abated of 400/ te CO 2e, theheating sector is a preferable end market.
Compared with decarbonisation in the electricity sector, Medium scale generation supported under the
FIT costs between 220 and 570/te depending on technology, offshore wind costs ~200/te, biomass
costs ~150/te and onshore wind costs ~100/te against a baseline of current grid average. This
suggests that the Bio-SNG case is preferable when compared with decarbonisation via feed in Tariffs,
offshore wind and anaerobic digestion
With regards to the cost of carbon abated, the renewables routes are relatively expensive. Whilst the
current renewable incentive structures are based on a duration which is commensurate with project
funding, the risk for this type of project is that in time, it is the price of carbon which becomes the
dominant incentive mechanism. This will highlight the relatively expensive cost of carbon abatement via
renewables, and may drive a change in policy. Without the kind of support proposed under the RHI,
projects such as Bio-SNG would not be viable.
The other key driver for the adoption of renewables is to establish alternative and secure sources of
energy through diversity, and where possible, indigenous supply. In this regard the use of waste based
fuels to provide a gas substitute offers a very low cost fuel source on a per MWh basis compared with
other renewables.
Risk assessment and financing considerations
The envisaged Bio-SNG facilities are in most respects conventional process engineering projects,
exhibiting the general risk profile that such developments entail. These can in the main be addressed
with a conventional contracting approach to risk management; however there are technology and
financing risks that need to be addressed.
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Although the process elements utilised in the development would be proven in their own right, there are
significant technical interfaces between them that need to be managed as part of overall systems
integration. This may require an innovative engineering and contracting approach, but it will be a
requirement to assure project funders that there is no significant residual technical risk inherent in such a
development.
The technical uncertainties implicit in the process integration will inevitably make project finance more
difficult and early development of a project financing strategy will be required in order to assure there will
not be a late in the day terminal event on this front.
Government incentive schemes offer the prospect of commercial viability with a plant that would not in
other circumstances be commercially viable; to that extent they are beneficial to non-fossil energydevelopments including Bio-SNG. The economic analysis shows that they do not constitute an
exceptional upside return on investment. What influences the attitude of investors however is that current
support mechanisms offer no protection on the downside of the project risk profile. It follows that a
financing strategy needs to make provision for managing the downside risk that will be perceived by
investors.
An incremental approach to the management of technical risk would be the development of a
demonstration facility, although even a reasonable scale demonstration facility might not necessarily open
the door to project finance on the first full scale plant. The demonstration plant would be required to
operate for a long time to assure process integrity, and further scale-up uncertainties associated with the
full sized plant would need to be managed Moreover this analysis suggests that a standalone
demonstration facility might itself cost in the order of 70M, a sum which would in any case represent a
financing challenge. The timeline for a demonstration facility also needs to be taken into account
especially in consideration of the competitive uses of the biomass resources and the timing of commercial
scale market penetration for BIO-SNG. Some of the investment risks could be mitigated by configuring a
Bio-SNG demonstration project on a syngas platform which is valorised mainly by another output product
such as electricity, with demonstration of Bio-SNG production via a slipstream. The financing of a Bio-
SNG project is a challenging prospect, however, it is important to start work on a financing strategy at the
outset of any prospective development, recognising the hurdles that do exist and devising methods to
overcome them.
Preliminary scoping of a demonstration platform in the North East
In light of the financial analysis, a project at 300MWth fuelled by SRF (or even a mixture of SRF and
virgin biomass) is economically viable. However, the quantum of investment for a first of a kind project is
substantial and would not be financeable without an intermediary pathway.
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Given the right support package, a demonstration project at 50MWth (75-100,000 te pa of feedstock)
could be feasible, but the economies of scale mean that the level of support necessary is substantial. The
combination of technical and commercial attributes, in addition to the current renewables incentive
regimes make a project configured to produce electricity a potentially more attractive platform. The
development of this commercial foundation could allow the demonstration of a slip stream of Bio-SNG at
more moderate additional cost.
Alternatively the demonstration of Bio-SNG production could be predicated on an existing or already
proposed syngas platform. In the Teesside region there are a number of such projects or proposals,
including the Ineos Bio facility, the proposed Air Products waste gasification scheme, or even the Eston
Grange IGCC which is anticipated to utilise a biogenic fraction in the feedstock stream. This approach
would not necessarily demonstrate the preferred gasification system. However, it would demonstrate thedownstream gas processing, methanation, and gas polishing process components, provide tangible
evidence of Bio-SNG production to grid quality specification and establish the protocols and precedent for
Bio-SNG injection into the grid. This, combined with demonstration of the appropriate and proven
gasification system for syngas production elsewhere, could provide an incremental pathway towards a
large scale project, subject to the comments made in the previous section.
The chemical and processing industrial heritage in the North East, its natural gas and services
infrastructure, its transport links and its track record of innovation make it an attractive region to locate
such a project, particularly given the syngas projects already slated.
With regards to potential new project sites, a high level screening exercise was carried out focused on
primary attributes (access to a deep water port, rail head &/or road access, gas connection NTS, or if
sufficient capacity LTS, electrical grid connection, commodities, water, cooling etc and desirable attributes
sources of rich hydrocarbons to boost gas quality, oxygen supplies, syngas main to valorise intermediate,
& potential to link into CCS networks for carbon dioxide disposal). In Teesside, potential areas considered
were Seaton Port, Seal Sands, Clarence Port, Billingham Reach, Norton Bottoms, South Bank, Corus,
and Sembcorp. Many of these sites were generally suitable for either scale of facility, with good access
to intermediate pressure gas grid (17-40bar) with sufficient capacity. Probably the most favoured sites
would be Clarence Port and South Bank. Both these areas are part of re-development plans, and given
an appetite to progress, the commercial feasibility of project on these sites could be investigated in more
detail.
Potentially one of the issues in locating the project in Teesside is feedstock supply. With regard to pure
biomass, Teesside and the North East already has over 300,000te already in use (Wilton10 and co-firing
at Lynemouth) with over 2 million tonnes per annum required for projects slated for development in the
area (MGT, Gaia Power and BEI). With regard to waste, SITAs Haverton incinerator already processes
390,000te pa of waste with a recent contract award and expansion plan for a further 190,000 te pa. SITA
and Sembcorp have also announced a planned Wilton 11 (400,000 te pa of household and commercial
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waste), the Ineos Bio facility will use 100,000 of SRF in the first phase and the proposed Air Products
gasification project will require 300,000 te pa. Combined these represent 1.4million tonnes of waste.
Many of these projects are still at the developmental stage and it is unlikely that all of these will progress
to completion, and also much of this feedstock would not be sourced locally, but it does indicate potential
pressure on resource. Conversely, some of these projects could provide a basis for a Bio-SNG
demonstration, given an appetite to drive forward a project by a Bio-SNG investor and an appetite on
behalf of the host site.
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2 Introduction
Methane is an attractive heat and transport fuel vector. It is a clean and relatively low carbon intensity
fuel. It can be utilised efficiently and has established infrastructure and demand-side technologies (gas
boilers for heating and an increasingly wide range of available CNG vehicles). The UK has one of the
most extensive gas networks in the world. Bio-methane retains all the attributes of natural gas, with the
crucial advantage that the fuel is renewable, offering substantial Carbon Dioxide savings. Few other
renewable vectors are as fungible, with so few demand-side constraints.
Figure 2.1 Methane, Biomethane and its merits and production routes
Biomethane can, and is being produced via the upgrading of biogas from Anaerobic Digestion. However,
in order to achieve a step change in production capacity, alternative approaches such as via thermal
routes (termed Bio-SNG) are necessary.
Figure 2.2 Schematic of Bio-SNG production
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The Bio-SNG approach accommodates a wider range of input feedstocks. It also converts the full calorific
value rather than only part of the biodegradable fraction. This also means that for Bio-SNG, the majority
of the mass and energy flow goes to the outturn product (gas). In anaerobic digestion, the majority of the
mass flow is to the residual digestate9. For these reasons the Bio-SNG approach can be executed at
more substantial scale.
Whilst technically feasible, this approach is less mature than anaerobic digestion. Transition from
aspiration, to widespread operating facilities and infrastructure requires a detailed understanding of the
technical and commercial attributes of the full chain from feedstock supply through to delivery of grid
quality gas, as well as the development of the first crucial operating facility which provides the tangible
proof of concept for roll out. The chemical and processing industrial heritage in the North East, its natural
gas and services infrastructure and its track record of innovation make it an attractive region to locatesuch a project.
This report lays out the key regulatory, feedstock, technical and economic issues, as well as the practical
considerations of a pathway from current status to an operating project.
9Digestate is an important co-product from anaerobic digestion, and its beneficial use is vital as part of a
sustainable biological cycle. However it does impose significant constraints on scale and location of anaerobic
digestion projects.
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3 Review of the fiscal, legislative and regulatory regime
Implementation of Bio-SNG will only take place with the appropriate tax, incentive and legislative
environment. Therefore it is critically important to establish the position that is pertinent to Bio-SNG
production on its own account, but also in comparison with the situation for other competitive users of
biogenic energy resources.
3.1 RENEWABLE ENERGY INCENTIVES AND INSTRUMENTS
Over the past decade UK government policy for renewable energy has been aimed at achieving
reductions in fossil carbon dioxide emissions emanating from the generation of electricity, from transport
fuels and more recently, from heating. Successive administrations have sought to achieve renewable
energy targets by means of Statutory Instruments that are intended to incentivise the development of
renewable energy assets. Key amongst these are:
The Renewable Obligations Order or RO
The RO was first introduced in 2002 and has been progressively developed in successive editions from
an originally simple concept that sought to deliver renewable energy at the lowest cost to the consumer
into a complex system that now seeks to promote technology developments in certain favoured
technology bands such as gasification and offshore wind, the lowest cost to the consumer criterion having
been dropped in the process10. The lesson to learn already from the brief history of the RO is that
incentive schemes are subject to constant adjustment, and changing political priorities. It follows that
developers must take advantage of the moment to secure a position because the longer a project takes to
develop the greater the potential for a change to the incentive landscape. The RO works by accredited
generators earning Renewable Obligation Certificate(s) for each MWh of renewable electricity exported;
electricity suppliers being obliged to sell a certain percentage of renewable electricity each year or else
pay the buy-out price for the shortfall. Funds arising from the buy-out are distributed to the generators
pro-rata to their relative renewables contributions.
The Renewable Transport Fuel Obligation
The RTFO came into law in 2008 as a means by which transport fuel suppliers could demonstrate
compliance with progressively increasing targets for the substitution of petroleum-based fuels in the retail
transport fuel mix. The RTFO works in a similar way to the RO concerning discharging of obligations by
production and trading of RTF Certificates, however, the unit of measure is the litre of fuel, rather than
anything that could relate to energy outputs and inputs, resource efficiency or carbon outcomes. It will be
readily appreciated therefore that a comparative assessment of the relative support levels afforded to
10. This Criterion has been noted again recently in the 2010 CSR with regard to FITS: 2.104 The efficiency of Feed -
In Tariffs will be improved at the next formal review, rebalancing them in favour of more cost effective carbon
abatement technologies.
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renewable electricity and renewable transport fuels is difficult to assess objectively. This becomes
important when the market seeks to direct biomass resources to the use that gives the greatest return for
the producer one sector may be disadvantaged relative to another. The RTFO only applies to a few
specific liquid fuel types and does encompass biogas for which the only support is the fuel duty
differential between methane and diesel/gasoline. The RTFO has had a chequered history, due to a
recent slowdown in targets, as well as a drafting error, the obligation has not generally provided a
bankable revenue stream.
The Renewable Heat Incentive
The Renewable Heat incentive is a long overdue support mechanism to rebalance renewable
development into the heat sector. This incentive includes support for direct injection of renewable gas into
the network. Following the Comprehensive Spending Review, HMT made the following press release on
the 20 Oct 2010.. 860 million funding for the Renewable Heat Incentive which will be introduced
from 2011-12. This will drive a more-than-tenfold increase of renewable heat over the coming decade,
shifting renewable heat from a fringe industry firmly into the mainstream. The Government will not be
taking forward the previous administrations plans of funding this scheme through an overly complex
Renewable Heat levy. From this it will be seen that the RHI has survived the spending review, albeit at
an ~80% reduction in support level but that there is still some clarification to be made concerning the
details of its operation and its implementation may be delayed beyond the original target date of April
2011, provisionally to June 2011. Clearly much depends upon a detailed appraisal and clarification of the
RHI concerning its potential to provide an appropriate level of support for Bio-SNG developments, andhow in detail the incentive cascades back to the Bio-SNG producer.
The Feed-In Tariff
The Feed-In Tariff was introduced in 2010 to incentivise the production of renewable electricity from small
facilities, avoiding the complexities of the RO by offering a fixed but uplifted electricity selling price. The
Comprehensive Spending Review indicates that the next FIT review will include changes intended to
focus development on those schemes thought to be most effective. Again it will be necessary to see if
there are any market distorting effects that could influence competition for solid bio-fuels.
EU Renewable Energy Directive
Late in the piece has come the EU Renewable Energy Directive (RED)which comes into law formally
by the 5thDecember 2010. The RED sets out targets for member states for the generation of energy from
renewable sources across all sectors, together with mandatory definitions of legal terms, units of
measurement and accounting. All domestic renewable energy legislation and practice must be
compatible with the RED definitions etc. otherwise it will be illegal. Clearly, the obvious discrepancies
between the RTFO and the remainder of the UKs renewables instruments must be regularised at some
point. The RED includes a definition of biogas and it appears that Bio-SNG would fall within the terms set
out in the directive concerning its eligibility as a source of renewable energy11. The RED also anticipates
11Unlike the UK Energy Act 2008 which does have a definitional issue which is undergoing resolution.
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the injection of methane from biogenic origins into the gas network and requires member states to
facilitate this activity. The RED sets specific sectoral targets including the achievement of 10% renewable
energy in surface transportation systems (a possible use of Bio-SNG) and encourages the use of waste-
derived materials by proposing double incentives for the use of energy derived from biogenic wastes.
3.2 ENERGY FROM WASTE REGULATIONS AND ISSUES
The use of waste derived fuels invokes additional regulatory considerations associated with the Waste
Incineration Directive (WID) as well as the need to assure the bio-energy contribution to the energy
release from mixed fossil / non fossil components. The drafting of the WID and its interpretation into
English or Scottish law presumes that waste derived fuels would be burned in an incineration plant. This
presumption leads to some difficulties when wastes are used in alternative energy schemes that were not
anticipated at the time of the WID drafting. Firstly the question of when a recovered material ceases to be
a waste continues to be a grey area. On the one hand recycled paper is considered to be recovered
when it is returned to raw paper pulp the pulp then being no longer subject to regulation as a waste.
The recovery of waste paper as a fuel, however, does not benefit from this interpretation; waste-derived
fuels are still considered to be wastesirrespective of their use and their intrinsic properties. Accordingly
energy plants fuelled by waste-derived fuels are subject to regulation under the WID, the syngas
produced by a gasifier still being regarded by the Environment Agency as a waste 12. The prevailing
wisdom from the Environment Agency is that the gas would continue to be a waste up to the point where
it is recovered i.e. burned. At face value this means that if Bio-SNG was to be produced from waste
and burned in a domestic heating appliance then the domestic heating appliance would need to comply
with the requirements of the WID. This is clearly a nonsense that would need to be formally and
unambiguously resolved before waste-derived fuels could be used in the production of Bio-SNG.
Accounting for the energy contributions from the fossil and non-fossil components of waste derived fuels
(i.e. miscellaneous biomass and various plastic rejects) is necessary in order to gain accreditation for
support for the bio-energy fraction under any of the renewables incentives listed above. To date this has
been a concern predominantly in the waste to electricity sector, but it is clearly going to be equally
important in a Bio-SNG development. Where a 100% biomass fuel is used it is a relatively simple matter
to assure the bio-energy content of the fuel and this can be achieved via an agreed fuel quality
management plan. With a heterogeneous waste derived fuel there are two possible methods to assess
bio-energy content in the fuelsampling and physical separation followed by classification and weighing,
or selective dissolution of biomass. Both require a sampling programme, which, given the inherent
variability of waste-derived fuels is subject to significant error bands and uncertainty unless a large
number of samples is taken into consideration. Even then it would be practically impossible to guarantee
how much of the bio-energy had reported to the final Bio-SNG product stream, and how much had been
associated with incidental process heat losses. The practical way to measure the bio-energy content of
12A recent EU Ruling at Lahti has set a precedent that a syngas may no longer be a waste. Whilst this is under
consideration in the UK, no such formal policy position has been set out as of the date of this report.
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the product SNG would be to use C14based techniques similar to those which are at present undergoing
demonstration to Ofgem in facilities generating electricity from wastes. Whilst the C14methodology for
determination of bio-energy content appears to be the favoured approach, it must be appreciated that
there is still some work to be undertaken before it is finally accepted by Ofgem as an appropriate
mechanism for accreditation of renewable energy content. Utilisation of C14in Bio-SNG production from
heterogeneous fuels would entail some further work beyond that, but for Bio-SNG it is probably the only
practical methodology for establishing bio-energy contribution from a heterogeneous fuel.
Electricity plants running on waste-derived fuels can, under certain circumstances qualify for enhanced
capital allowances against corporation tax but this will also require operators to give evidence of biogenic
energy contribution for which C14based systems would be ideally suited. It is also unclear if such benefits
could accrue to Bio-SNG facilities.
3.3 EMISSIONS TRADING
Under the European Emissions trading Scheme (Eu ETS) all power plants with a thermal rating of greater
than 20MW are required to register and report their GHG emissions. The implementation of the ETS is
Phased from its initial introduction in 2005 (Phase 1), with Phase 2 running from 2008 to 2012 whereafter
the third and ultimate scope of the ETS will be imposed. The objective of the Eu ETS is to set a cap on
gross Eu GHG emissions reducing annually from a figure of 1927m tonnes CO2 equivalent in 2013; this
figure being shared, by a process of negotiation, between the member states. In each phase and year of
the implementation a progressive lowering of the free carbon allowances will be imposed, obliging
thereby the operators to progressively reduce their own GHG emissions or else to buy surplus allowances
in the market from those with a surfeit of allowances. Whilst all thermal power plants of greater than
20MWth are required to register under the Eu ETS, certain types of plant are exempt from the need to
limit their annual GHG emissions; these include facilities running on pure biomass. It will be apparent
therefore that a Bio-SNG plant running on pure biomass will not be required to obtain emissions permits
under the Eu ETS, but where a waste-derived fuel that includes some fossil carbon is used then the ETS
becomes not only a regulatory consideration but fossil carbon emissions need to be accounted for and
measured. This may require a particular treatment because some of the energy release will be local, with
the remainder being consigned to the pipeline. It should be noted that Municipal facilities are exempt
from the provisions of the Eu ETS, hence a plant operating primarily to deliver a municipal waste
management service ought to be exempt. The status of a potential Bio-SNG plant appears to be
somewhat obscure with respect to the Eu ETS, therefore it is recommended that early in the development
programme clarification should be sought concerning whether such a plant would be eligible / liable, and
also how the question of a percentage of fossil carbon in the feedstock should be handled. (Note that the
Bio-SNG plant will be a direct producer of carbon dioxide resulting from acid gas removal post shift and
pre methanation reactions. With a waste-derived fuel some of this will have a fossil origin.)
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3.4 THE GAS SAFETY MANAGEMENT REGULATIONS
The Gas Safety Management Regulations (GS(M)R)set out the rules for transportation of natural gas
throughout the gas network, from producer to customer and will be well understood by gas industry
practitioners. Of critical importance to the design of Bio-SNG facilities, Schedule 3, Regulation 8 of the
GS(M)R defines the allowable gas composition for gas transported through the network; the relevant
section being included in this report as Appendix 3. As discussed in Section5.5 the main challenge for
Bio-SNG production is the hydrogen content specified in the GS(M)R13
, however it may be possible to
achieve some derogation of this by examination of the methodology outlined in article 192 of Schedule 3
of the GS(M)R14.
3.5 OTHER KEY REGULATIONS
TheLarge Combustion Plant Directive (LCPD)seeks to regulate the emission of SOx, NOx and dust
from power plants with a thermal rating of 50MWth or more. Whilst both the subject demonstration scale
plant and the full scale plant reach or exceed this thermal power input it would appear that neither would
be subject to the LCPD. Article 2 (&) of the Directive states:
This Directive shall apply only to combustion plants designed for production of energy with the exceptionof those which make direct use of the products of combustion in manufacturing processes.
On this basis, given that in a Bio-SNG plant the products of combustion are used to make methane, such
a plant would not be regulated under the LCPD. However, a Bio-SNG plant, just like any other large
industrial process facility would fall within the IPPC regulations and be required to secure an
Environmental Permit. This should not constitute a particular development hurdle, but it would constitute
a significant expenditure and must be commenced early in the development to avoid the risk of delays to
financial close.
13Unlike for anaerobic digestion derived biogas, for which oxygen content is one of the key challenges
14
The full GS(M)R can be obtained as a downloadable .pdf file from:
http://books.hse.gov.uk/hse/public/saleproduct.jsf?catalogueCode=9780717611591
http://books.hse.gov.uk/hse/public/saleproduct.jsf?catalogueCode=9780717611591http://books.hse.gov.uk/hse/public/saleproduct.jsf?catalogueCode=9780717611591 -
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4 Feedstock
Biomethane production via synthesis gas can be generated from any biomass fuel which can be gasified.
Potentially this encompasses pure biomasses such as woodchip, energy crops or biogenic co-products
from biodiesel production, crude bio-oil from wood pyrolysis, to discarded materials such as waste wood,
or processed wastes such as Solid Recovered Fuels. This review will provide a high level perspective on
fuel types and the technical implications on the process, as well as the commercial and sustainability
issues.
The use of bio-fuels for heating and lighting pre-dates the use of fossil fuels by thousands of years,
nevertheless a systematic knowledge base of the challenges posed by solid bio-fuels is not as widelyunderstood as is the case with fossil fuels, a fact attributable to the burgeoning use of fossil fuels as
exponentially increasing demand powered the industrial revolution across the globe. In the emerging
post-fossil epoch that is beginning now, producers and users of thermal power are considering the use of
biomass in applications in which the use of fossil hydrocarbons has been dominant electricity
generation, heating, transport fuels, organic chemicals, synthetic materials, and synthetic natural gas or
SNG.
4.1 THE SIGNIFICANCE OF BIO-SNGIN THE ENERGY SCENE
The primary energy consumption of the United Kingdom is approximately 10 Exajoules per annum15
, of
which nearly 40% is supplied by natural gas, making gas the UKs largest single energy source, with an
extensive infrastructure and expertise base.
Figure 4.1 Natural gas flow chart 2008 (TWh)16
151 Exajoule is 1X10
18Joules, written conventionally as EJ
16Digest of United Kingdom Energy Statistic2009
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With the ever rising need to secure future energy diversity and reduce greenhouse gas emissions it could
be a considerable advantage if use could be made of the gas infrastructure and the expertise of the
efficient industry that has developed around it by the use of synthetic natural gas (SNG), including SNG
derived from renewable resources such as biomassBio-SNG.
4.2 PUREBIOMASS RESOURCES
In coming to a view on the potential merit of Bio-SNG it is necessary to consider the magnitude of
biomass resources in order to establish the scale of the benefits that might be realised in practice. Note
that this report does not address the potential of biogas derived from the digestion of organic matter in
landfills and anaerobic digesters but concentrates upon the thermochemical production of methane from
biomass types that are generally not digestible, i.e. woody biomass. Woody biomass can be classified
according to its provenance; for example energy crops, agricultural and arboricultural residues, industrial
co-products, and waste materials such as recovered wood.
A certain amount of work has been accomplished to date on the quantities and prices of biomass fuels
that could be obtained both from indigenous sources and on international markets17, and is collated in
Table 4-1
Fuel type Indigenous Import Global
Energy crops 60 -550 PJ/a
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for the solid biofuels remains a considerable challenge each depending upon the other with investment
decisions requiring certainty for both supplier and user.
Estimates vary for indigenous production capacity for energy crops ranging from 60 PJ to 550PJ per
annum depending upon the extent to which subsidies may be paid to growers to compensate for the lag
between planting and harvest and sales18. It is interesting to note the implicit assumption that subsidies
for energy crops are required to get the supply chain established rather than to compensate for the
intrinsically higher cost base associated with energy crops pending the date when rising fuel prices could
be expected to reach and overtake these. An investor in a plant using solid biofuel crops ought therefore
to satisfy itself that the cost of producing energy crops is not disadvantageously indexed to the prevailing
cost of energy, or else gain satisfaction that support mechanisms would be sustained for a sufficient
period of production and operation to assure commercial viability for both producer and user.
Woodchip
In the UK, half of the commercial forestry is operated by the forestry commission, with the balance under
private management. Approximately 9 million green tonnes are extracted per annum for timber
production. Green timber is 50-55% moisture as harvested, although with seasoning can be reduced to
30% naturally over time, without additional heat. This material can be utilised as woodchip, although its
use is in direct competition with sawlog. Small roundwood is less valuable than sawlog, so woodchip can
be sourced from this material. Other than saw-wood, there is a variety of lower grade timber available
from forestry and the urban environment. In managing forestry, brash (removal of ancillary stems),
thinning (trees which are too small for extraction) and poor quality final crops, can be extracted. Many of
these are left on site, however, as the market for biomass fuels expands, these are a lower cost source of
timber. The arboricultural arisings in England, Scotland and Wales by Forest district, estimated to be
c.670,00019oven dried tonnes per annum (12PJ pa). Similarly, in the urban environment and on road and
rail-sides tree management gives rise to arboricultural arisings. These are usually chipped, and often
landfilled, but are increasingly being viewed as another energy biomass source.
Internationally woody biomass has the potential to be sourced from highly forested countries such as
Canada and Russia, with often distressed products being identified (such as beetle killed spruce). In the
UK over 250PJ of international woody biomass resources have been slated for use in electricity projects.
Whilst these resources are substantial, these commodities require extraction, haulage, shipping,
unloading and delivery into plant, noting that the energy density of biomass is low relative to fossil fuels.
As international jurisdictions develop renewable energy policies and seek to secure resources for their
energy needs, international competition for these fuels will become more intense.
18DECC - Biomass supply curves for the UKE4Tech - March 2009
19 Woodfuel Resource in Britain FES B/W3/00787/REP/2 DTI/Pub RN 03/1436 (2003)
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Trends in the biomass to power market indicate that major users of solid biofuels are moving upstream in
the fuel supply chain in order to secure their future fuel deliveries. The recent take-over of the Dutch
company Essent by RWE was made for this specific purpose; RWE recognising that Essent had already
established a trading arm that is dedicated to the sourcing, transportation and trading of biomass fuels,
with a view to expansion of this business to meet the anticipated demand for biofuels. With the
expanding demand for biofuels it is becoming increasingly clear that developers of biomass fuelled
facilities need to take overt measures to manage fuel supply uncertainties (price, quality, availability,
sustainability), at least for the purpose of constructing a bankable case for project finance.
4.3 PROPERTIES OF PUREBIOMASS FUELS
The development of industrial scale gasification of coal has occurred over a period of more than 100
years and is the subject of a vast body of science and technology. The success of this industry is built
upon years of investment, research and development and operating experience. It is frequently
assumed, mistakenly, that the industrial gasification20of biomass is more difficult, evidenced by the slow
pace of development in this area. The lack of development would be more reasonably attributable to the
novelty of the process and the small scale of the industry, rather than any fundamental technological
limitation. Nevertheless, in contemplating the production of SNG from biomass it is essential to
understand the significant differences between biomass feedstocks and the more widely understood
properties of coals.
For gasification, the fuel properties of most interest are; fixed / volatile carbon, carbon, hydrogen, oxygen,
nitrogen, ash content, ash fusion temperature, and humidity.
Sub bituminous coal (typical) Wood fuel (typical)
Fixed carbon % 44.7% 20%Ash content %. [DB] 4.3% 1.2%
Ash Fusion temperature (C) 1230 to 1600 > 850
Sulphur % [DAF] 0.5%
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Although many of the macroscopic properties of biomass are remarkably similar across a number of
species it is important to note that minor constituents can vary with the species 21and undoubtedly with
the environment and soils in which they are grown. (Scientific literature is prolific on the subject of mineral
take-up from the environment, with some plant species being especially effective in accumulating, lead,
zinc, mercury etc.) This is particularly important when considering the properties of biomass ashes,
which in themselves are notably dissimilar to coal ashes, both in the amount and also their chemical
composition. This has implications for chosen gasifier operating conditions especially with respect to ash
fusion temperatures and the volatile behaviour of certain alkali metal oxides at elevated temperatures.
Furthermore, gas processing operations may be sensitive to small levels of both alkali metals and heavy
metals in the de-activation of catalysts.
The European Commission recognised the need for a systematic basis to describe solid biofuels and in2004 embarked upon a programme of work under CEN/335 entitled Solid Biofuels. The objective of the
work was to provide a scientifically informed basis for describing the properties of solid bio fuels for the
purpose of facilitating trade between producer and user, for informing process design, (esp. materials
handling), environmental permitting, communication with stakeholders and for quality management.
4.4 WASTE MATERIALS
Over 98% of the potential UK indigenous biomass resource is from waste products22. Municipal,
commercial and industrial wastes therefore provide a valuable and ubiquitous source of biomass fuel.
Combustible wastes arising from household collections, commercial-industrial waste and construction and
demolition23
. Whilst there is significant political pressure to increase recycling, analysis by Lee et al
clearly shows that even extensive recycling will still leave a substantial tranche of residual material for
which recycling is not possible. This data, Figure 4.2 shows that the residual waste from municipal
sources is predicted to be fairly constant at c.28million tonnes and from commercial/industrial sources at
50million tonnes. Of this c.17million and c.24million tonnes are considered to be biomass respectively.
The authors estimate this residual waste resource (biogenic and non-biogenic) to be ~700PJ from both
MWS and C&I streams. This full potential analysis does not account for existing uses for the residual
wastes, nor the availability of the streams (this is discussed in Section4.7)
21
Biomass and Bioenergy Vol. 4,No. 2, pp. 103-116, 199322Gill et al, Biomass Task Force Report (2005)
23 Lee P et al, Quantification of the Potential Energy from Residuals (EfR) in the UK Commissioned by The
Institution of Civil Engineers. The Renewable Power Association (March 2005) Oakdene Hollins Ltd
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Municipal Waste arisings
0
20
40
60
80
100
2005 2010 2015 2020
MillionTonnespera
nnum
Bio Residual Non Bio Residual Recycled
Commercial and Industrial Waste arisings
0
20
40
60
80
100
2005 2010 2015 2020
MillionTonnespera
nnum
Bio Residual Non Bio Residual Recycled
Figure 4.2 Municipal, commercial and Industrial waste arisings in the UK
The production of Solid Recovered Fuel (SRF) from non-hazardous wastes creates the opportunity to
utilise waste derived fuels in thermal applications that are more sophisticated than the classical waste
disposal route via incineration; in particular SRF is being regarded increasingly by a number of producers
and users as a potential feedstock in gasification. Hence there is the potential for the transformation of
combustible wastes into syngas and its products including SNG.
The term SRF arises from work undertaken by the European Commission under CEN/343 to provide a
systematic basis for the classification and standardisation of fuels derived from non-hazardous wastes.
This work was undertaken in the anticipation that the energy content of non-hazardous wastes should be
exploited in pursuit of increased resource efficiency within the EU. CEN/343 therefore set out to define a
scientifically informed basis for describing the properties of waste derived fuels for the purpose offacilitating trade between producer and user, for informing process design, environmental permitting,
communication with stakeholders and for quality management24.
It will be readily appreciated that it is not feasible to design a piece of sophisticated plant such as a
gasifier without tailoring the design to the known properties of the fuel. This is true for a conventional coal
gasifier and it is equally the case for a gasifier intended for operation on biomass or a waste-derived fuel.
Given the variable provenance and properties of waste materials it becomes an indispensable condition
that some method must be applied by which the physical and chemical properties of a waste-derived fuel
can be specified and assured, if they are to be used as a gasifier feedstock. The CEN/343 approach
provides a rigorous method to do this.
The properties of solid fuels which are of most interest in gasification are common, whether they are fossil
or biomass or waste. These include particle size and density, physical form, ash content, ash fusion point
and ash composition, humidity, and levels of halogens, sulphur, arsenic, and mercury. An operator of a
coal gasifier can control the inputs to its plant by using coal from well characterised sources, even
individual mines, backed up by standardised coal testing techniques that have been in use for decades.
The use of SRF in gasification introduces therefore the need for an equally effective means of fuel quality
assurance.
24CEN/343 is now mandated for adoption by member states and is available from British Standards Institute.
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In postulating the use of SRF for the production of Bio-SNG, it is necessary to understand the bio energy
content of the fuel. CEN/343 includes methods for making this determination, but they may not provide
the best method of biomass determination.25 It must also be appreciated that when SRF is used for
production of SNG, a proportion of the output would contain fossil carbon, and this would need
accounting for if incentives for renewable energy were to be claimed. The composition of a typical Solid
Recovered Fuel is shown inTable 4-3
SRF class and origin
Class code : NCV 3, Cl 3, Hg 3
Physical parametersParticle form : Cubes
Particle size : Test method: prCEN/TS 15415
Unit Value Test method
Typical Limit
Ash content % dm 14 25 prCEN/TS 15403
Moisture content % ar 8 20 prCEN/TS 15414
Net calorific value (NCV) MJ/kg ar 18 >12.5 prCEN/TS 15400
Biomass fraction % GCV 65 50 prCEN/TS 15440
Chemical parametersUnit Value Test method
Typical Limit
Chlorine (Cl) % w/w 0.26 1.0 prCEN/TS 15408
Sulphur (S) % w/w 0.15 1.0 prCEN/TS 15408
Fluorine (F) % w/w 0.02 0.5 prCEN/TS 15408
Bromine (Br) % w/w 0.01 0.25 prCEN/TS 15408Mercury (Hg) mg/kg 0.49 10 prCEN/TS 15411
Cadmium (Cd) mg/kg 1.26 20 prCEN/TS 15411
Thallium (Tl) mg/kg < 9 20 prCEN/TS 15411
Total Group II metals mg/kg 18 30 prCEN/TS 15411
Antimony (Sb) mg/kg 12 150 prCEN/TS 15411
Arsenic (As) mg/kg < 0.82 100 prCEN/TS 15411
Chromium (Cr) mg/kg 17.6 150 prCEN/TS 15411
Cobalt (Co) mg/kg 4.3 75 prCEN/TS 15411
Copper (Cu) mg/kg 268 500 prCEN/TS 15411
Lead (Pb) mg/kg 100 250 prCEN/TS 15411
Manganese (Mn) mg/kg 90 500 prCEN/TS 15411
Nickel (Ni) mg/kg 9.3 100 prCEN/TS 15411
Tin (Sn) mg/kg 27 50 prCEN/TS 15411Vanadium (V) mg/kg 4.1 50 prCEN/TS 15411
Total Group III metals mg/kg 538 800 prCEN/TS 15411
Table 4-3 Typical SRF specification
Failure of waste gasification processes has been frequently exacerbated by not only the uncontrolled
variability of the fuel, but also by the failure of technology developers to appreciate the importance of this
issue in process design. Unlike a waste incinerator, a waste fired gasifier cannot be omnivorous; fuel
specification and plant design are inextricably linked.
25
C14
methods applied to the process output may give more reliable performance and be cheaper.26dry matter (dm)
27as received (ar)
28wet weight (w/w)
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4.5 TOTAL AMOUNT OF BIOMASS RESOURCE FOR BIO-SNGPRODUCTION
Notwithstanding the considerations outlined above it is necessary to postulate the amount of biomass fuel
(pure and waste derived) that could reasonably be procured for the production of SNG, both from
indigenous and overseas sources, and thereby form an estimate of the significance of the ensuing Bio-
SNG production in the UK gas market. Figure 4.3 shows such a figure, assuming that 1EJ of biomass
could be sourced indigenously and from international markets, and that 33% of that could be used for the
production of Bio-SNG for use in heat and transport applications at a conversion efficiency of 66%. This
would represent 15% of the UK domestic gas market.
Figure 4.3 Potential role for Bio-SNG as a function of the UK domestic Gas market
4.6 COMMERCIAL CONSIDERATIONS FOR PUREBIOMASS
To see biomass as simply a replacement for a fossil fuel such as coal is a mistake on account of its
dispersed provenance, its chemistry, humidity and its lower energy and bulk densities. It is equally
important to recognise that biomass has the potential to be a feedstock across a wide spectrum of users
and industries, whether transformed into synthesis gas (syngas) - the universal feedstock for the organic
chemicals industrysynthetic materials such as plastics resins and polymers, drugs and pharmaceuticals
- power generation, liquid transport fuels, and SNG, or used for space heating or as it is as a construction
material - timber. The growing demand for biomass in these applications will set the market price
globally. It is also evident that potential demand for biomass feedstocks across all of these sectors could
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easily exceed global production capacity from the outset, a situation that paradoxically is only just
beginning to impact on crude oil prices at the end a century of exponentially increasing oil production from
a vast but finite resource. Competing users of biomass feedstocks will set the market price, with
governmental support mechanisms for biomass electricity already having a dominant effect and being
criticised as contributing to unfair market distortion29.
The traded price of clean biomass fuels for biomass power generation is today in the range of 6 to 7
per GJ measured as net calorific or lower heating value, a price that would be unaffordable by operators
of biomass power stations without support through a variety of inward looking national support
mechanisms30
. The relative generosity of the various national support mechanisms is not formally
coordinated throughout the EU, and it is most certainly uncoordinated globally. Asymmetry between
national support schemes for power generation from globally traded biofuels remains a significantcommercial threat to the viability of schemes that utilise such fuels
31. It is also the case that asymmetry of
support mechanisms across market sectors within the UK constitutes a business threat to any company
for whom consequent price distortions would affect their business case. (Users in receipt of the most
advantageous support will be market price makers, all others will be price takers.)
The effect of asymmetry in support mechanisms is to give one class of users a dominant position in the
fuel market In conditions of supply constraint this constitutes a lock-out to other potential users of a
biomass resource. Hence in the domestic UK situation the Renewables Obligation (and the SRO and
NIRO) rewards electrical power generation more favourably than would the RTFO reward the use of an
equivalent amount of resource in the production of synthetic transport fuels. Accordingly the purchaser of
a biomass resource will seek to use it in the application yielding the greater added value power
generation. Developers of biomass to liquids plants will not move until an equivalence of incentives (at
least) would be forthcoming. In contemplating the development of an SNG facility, considerations of
analogous factors should be undertaken; these would include the impending Renewable Heat Incentive
(RHI), fuel costs, the specific SNG yield, power sales prices, and Bio-SNG selling price, together with
plant capital and operating costs.
4.7 COMMERCIAL CONSIDERATIONS FOR WASTES
The production of wastes does not mean necessarily that they are available to the market. Municipal
authorities have for many years been required to meet increasingly onerous targets for the long term
management of their waste streams. This has involved local authorities in committing to long term
contracts with waste contractors, in which their waste streams are likely to be tied up for periods of 20 to
29See BWPI FederationLarge-scale biomass threatens 8,700 UK jobs... ...and risks a 1% increase in UK
emissionshttp://www.wpif.org.uk/Make_Wood_Work_News.asp30
Coal prices are in the region of 2 per GJ; the price differential to biomass being more than sufficient topurchase carbon offsets or allowances with carbon trading at any price up to approximately 30 per tonne.31
Note the way in which different approaches to support for transport biofuels in North America and UK
precipitated a sequence of events that seriously damaged the UK indigenous biofuels industry in 2008/9.
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25 years. The over-riding principle that sits behind municipal waste management is that local authorities
need to have long term certainty over price and deliverability from their contractors; uncertainty (including
technical uncertainty) over reliability of off-take or price is usually unacceptable to them.
The economic driver in the commercial industrial waste market rests predominantly with the landfill tax;
hence a rational market exists in which operators seek the lowest cost of disposal for those materials that
do not command a revenue from recycling. Historically, the lowest cost of disposal has been given by
landfill, but with the inexorable increase in the level of landfill tax waste handlers are increasingly looking
to other forms of disposal that might be competitive. This has lead to an increasing interest in disposal of
combustible wastes via energy recovery facilities, whether by mass burn incineration or via production of
solid recovered fuels (SRF).
Under certain conditions32
energy from waste facilities have the potential to secure Renewable Obligation
Certificates and hence benefit from additional power income33
. The potential of gasification to secure
double ROC eligibility has promoted development activity in this area, where a gasification project could
be commercially viable at a small scale given the additional revenues promised by double ROCS and a
gate fee for taking waste-derived fuels.
In the existing UK market the users of waste-derived fuels demand and are able to receive a gate fee in
the range of 20 to 50 per tonne, irrespective of the quality or energy value of the fuel. This is because
the next cheapest option available to producers is disposal via landfill. This represents a major benefit to
the fuel user, but there are already signs that the market is changing, with continental users offering to
pay a small cost per tonne, and UK producers exporting SRF to continental users in the face of an
increasing demand for the product. It follows that in creating a business case for the production of
syngas from SRF it would be a mistake to assume that the price of SRF will always be a large negative
number. Nevertheless, the cost benefit of SRF compared to energy crops means that the marginal
scales of commercially viable facilities running on these fuels are likely to be quite different. This may be
important for early Bio-SNG projects where the risk profile of a first-of-a-kind plant might prohibit
development at the scale required to ensure a commercial return when using bio-crop fuels.
32Conditions include: either the use of an advanced thermal process such as gasification, or the achievement of
GQ CHP in a combined heat and power plant.33
The RHI holds a similar promise, though the rules regarding eligibility are not yet defined.
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4.8 FEEDSTOCK CONCLUSIONS
In planning the production of Bio-SNG consideration must be given to the ultimate capacity that is
contemplated and a strategy put in place to secure the quantity and quality of feedstock that would be
required, at an acceptable cost, and in a market where competing large scale uses of biomass feedstocks
are being developed simultaneously throughout the world.
Commercial viability will be influenced by governmental support in the renewables sector. It follows that
Bio-SNG developer should seek to ensure it is able to compete in the fuel market with other biomass
users.
The properties of biomass fuels should be understood and controlled to required quality levels, whether
virgin biomass, or recovered materials. Reliability of process plants will depend upon this.
In summary, it is likely that the development of Bio-SNG facilities will require the developer to go
upstream into the supply chain for both grown and waste derived fuels, however, specification and quality
control are vital determinants of project success.
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5 Process and Technology Review
The focus of this section is not to undertake a panoramic review of potential technologies in various
states of maturity; that has been done elsewhere34
. Rather it is to focus on a rationale for the
configuration of a practical plant that could, subject to commercial considerations be deployed now at an
industrial scale.
Experience reveals that process developments are rarely founded on technological break-throughs;
rather it is normally the case that process developments are incremental and founded upon existing
proven techniques. The guiding principle in this review has been therefore, to establish whether existing
technologies could be employed for the entire process chain from fuel reception and preparation throughto Bio-SNG compression and delivery, and in a way that gives a good level of performance in comparison
with alternatives and with respect to efficiency, technical risk, commerciality and speed to market.
The development of a processing scheme should be dominated by an understanding of the desired
output stream as well as the properties of the feedstock; including a precise understanding of the levels of
contrary elements in the fuel such as heavy metals, sulphur and halogens. This drives the requirements
and specification for the intervening processing stages. An overall appreciation of the principal process
operations required for the production of Bio-SNG is shown inFigure 5.1 below.
FUEL PREP
THERMO-
CHEMICAL
BREAKDOWN
INTERMEDIATE
PURIFICATION
INTERMEDIATE
CONDITIONINGMETHANATION
POLISHINGPACKAGING
including
COMPRESSION
PRODUCT
Bio-SNGPRODUCTS: HEAT, ELECTRICITY, OTHER CHEMICALS AND FUELS
BALANCE OF PLANT
Figure 5.1 Principal Process operations
A systematic process review therefore will begin with the fuel handling facilities - reception, storage,
preparation and feeding arrangements.
5.1 BIOMASS RECEPTION,PREPARATION AND HANDLING.
The operational effectiveness of the gasification process plant will depend upon the continuous supply of
fuel exhibiting regular propertiesparticle size, density, humidity, calorific value, chemical analysis, etc.
34e.g. NNFCC project 09/008: Review of Technologies for Gasification of Biomass and Wastes:E4Tech June 2009
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A key design consideration therefore is whether to import material of a defined specification and quality or
to manufacture the fuel on site from raw biomass or residues. On the one hand manufacture on site will
demand more space, more plant, a larger workforce and a significant parasitic energy consumption,
however on the other hand, bought-in ready to use fuel will be more costly, and could subject the plant to
greater supply chain vulnerability. Moreover biomass drying is likely to be a significant feature of the fuel
preparation process and could represent an economically effective use of waste heat from the gasification
process. A balanced judgement needs to be taken, therefore, on the fuel supply philosophy, taking into
account, the type of raw feedstock (lumber, waste wood, wood chip, pellets, miscellaneous biomass
residues, commercial / industrial waste etc.), the plant location, the space available, and the fuel supply
chain arrangements.
Th