bio sng feasibility study

7/25/2019 Bio SNG Feasibility Study

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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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BIO-SNGFEASIBILITY STUDYESTABLISHMENT OF A REGIONAL PROJECT

2

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

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