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Bio‐SNG

Feasibility Study. Establishment of a Regional Project

Progressive Energy & CNG Services

Clients: NEPIC National Grid

Centrica Date: 10/11/10 Issue: Vs 2.3

BIO-SNG FEASIBILITY STUDY – ESTABLISHMENT OF A REGIONAL PROJECT

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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 .......................................................................................................................................... 14

3 Review of the fiscal, legislative and regulatory regime ....................................................................... 16

3.1 Renewable Energy Incentives and Instruments ......................................................................... 16 3.2 Energy from Waste regulations and Issues ................................................................................ 18 3.3 Emissions Trading ...................................................................................................................... 19 3.4 The Gas Safety Management Regulations ................................................................................ 20 3.5 Other key regulations ................................................................................................................. 20

4 Feedstock ............................................................................................................................................ 21

4.1 The significance of Bio-SNG in the energy scene ...................................................................... 21 4.2 ‘Pure’ Biomass resources ........................................................................................................... 22 4.3 Properties of ‘pure’ biomass fuels .............................................................................................. 24 4.4 Waste materials .......................................................................................................................... 25 4.5 Total amount of Biomass resource for Bio-SNG production ...................................................... 28 4.6 Commercial considerations for ‘pure’ biomass ........................................................................... 28 4.7 Commercial considerations for wastes ....................................................................................... 29 4.8 Feedstock Conclusions .............................................................................................................. 31

5 Process and Technology Review ........................................................................................................ 32

5.1 Biomass reception, preparation and handling. ........................................................................... 32 5.2 Gasification ................................................................................................................................. 33 5.3 Gas Processing .......................................................................................................................... 39 5.4 Methanation ................................................................................................................................ 41 5.5 Gas conditioning, compression and metering ............................................................................ 42 5.6 Conclusions on Process and Technology .................................................................................. 43

6 Economic Assessment ........................................................................................................................ 44

6.1.1 Scale and operational assumptions........................................................................................ 44 6.1.2 Investment Cost assumptions ................................................................................................ 45 6.1.3 Operating Cost assumptions .................................................................................................. 48 6.1.4 Feedstock ............................................................................................................................... 48 6.1.5 Revenue Assumptions ............................................................................................................ 50

6.2 Levelised Cost analysis .............................................................................................................. 50 6.3 Sensitivity Analysis ..................................................................................................................... 54

6.3.1 Escalation ............................................................................................................................... 55 6.3.2 Impact of capital Cost, Opex, Fuel price, RHI and heat sales ................................................ 56 6.3.3 Comparison with an SRF fuelled electricity project ................................................................ 57

6.4 Financial conclusions ................................................................................................................. 58 7 Lifecycle carbon emissions and Cost of Carbon Analyses compared with alternatives ..................... 60

7.1 Lifecycle carbon emissions ......................................................................................................... 60 7.2 Cost of carbon abatement via Bio-SNG ..................................................................................... 64

8 Risk Assessment and Financing Considerations ................................................................................ 69

8.1 Conclusions from risk assessment and financing considerations .............................................. 74 9 Preliminary Scoping of a lead, beacon project .................................................................................... 75

9.1 Beacon Project configuration options ......................................................................................... 75 9.2 Location: The North East ............................................................................................................ 77 9.3 Site analysis................................................................................................................................ 78 9.4 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 of

the 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 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. 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 180EJ1 per 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/a2 of 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 seller

and 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 = 1018Joules 2 1 Petajoule = 1015 Joules 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 entrained

flow 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 optimised process 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 investment5 and 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.

4 “Biomass prices in the heat and electricity sectors in the UK”, Department of Energy and Climate Change (January 2010) 5 £65‐£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 in

international 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

costs per 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 more likely 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

6 Energy and emissions projections, DECC (June 2010) Annex F


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support to demonstrate Bio-SNG production. At 300MWth, a gasification facility configured to generate

electricity is likely to be commercially preferable to one configured to produce Bio-SNG, unless the

Renewable Heat Incentive is significantly higher than the £40/MWh proposed.

Carbon savings

A full lifecycle analysis of Bio-SNG production undertaken by North Energy Associates7 shows that for

many types of feedstock, the lifecycle CO2e savings of Bio-SNG compared with fossil fuel alternatives are

typically ~90%. This saving is similar for both conventional heating and transport applications. The annual

CO2e savings for three of the larger facilities operating on biomass is 1Mte of CO2e per annum if used to

displace natural gas heating, and slightly higher if it displaces conventional transport fuel. If Biogas were

to displace a third of the domestic natural gas consumption and bio-SNG represented two thirds of that,

then the CO2e savings would be ~15Mte pa when fuelled by biomass.

This analysis also demonstrates that the savings for the Bio-SNG production route are very similar to

those achieved using direct biomass heating. Given that the Bio-SNG solution has much lower demand-

side constraints and therefore could achieve greater market penetration, it is an attractive route.

Cost of carbon abated

Strategically the UK needs to consider the most cost effective approach for decarbonising. An analysis

has been undertaken which considers the cost of decarbonising, based on the current and proposed

levels of renewable support subsidy8 considered to be adequate to achieve market penetration of the

particular technology.

For heating applications using natural gas as a counterfactual, Bio-SNG offers a cost per tonne of CO2e

abated of ~£175/te. This compares very favourably with direct biomass combustion for domestic

applications (£395/te), for small commercial applications (£285/te) but is somewhat more expensive than

direct biomass combustion for large scale commercial applications at ~£110/te. When using oil heating as

the counterfactual, the cost per tonne of CO2 saved reduces significantly to £135/te for Bio-SNG

compared with £305, £220 and £85 for the three cases discussed above. However it must be noted that

the appropriate counterfactual for Bio-SNG is natural gas, as the product can only be used where there is

a gas grid and where oil use is unlikely.

7 “Analysis of the Greenhouse Gas Emissions for Thermochemical BioSNG Production and Use in the United Kingdom” Project Code NNFCC 10‐009 Study funded by DECC and managed by NNFCC, North Energy Associates (June 2010) 8 In deriving the cost of the emissions savings, the Government’s Impact Assessments calculation is made on the basis of dividing the NPV of the incentive by the total tonnes of CO2 abated. The analysis here is viewed from the point of view of the direct cost to the consumer, ie the subsidy cost divided by the tonnes of CO2 saved, and where possible uses the full lifecycle emissions of CO2e.


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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 CO2e, the

heating 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 energy

developments 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 the

downstream 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, SITA’s 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 locate

such 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.

9 Digestate 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.”


17

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 administration’s 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, and

how 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 5th December 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 UK’s 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

11 Unlike the UK Energy Act 2008 which does have a definitional issue which is undergoing resolution.


18

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 wastes – irrespective 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 waste12. 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 fuel – sampling 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 12 A 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.


19

the product SNG would be to use C14 based techniques similar to those which are at present undergoing

demonstration to Ofgem in facilities generating electricity from wastes. Whilst the C14 methodology 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 C14 in 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 C14 based 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.)


20

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 Section 5.5 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 The Large 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 exception of 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.

13 Unlike 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=9780717611591


21

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 widely

understood 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-SNG IN 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 UK’s largest single energy source, with an

extensive infrastructure and expertise base.

Figure 4.1 Natural gas flow chart 2008 (TWh) 16 15 1 Exajoule is 1X1018 Joules, written conventionally as EJ 16 Digest of United Kingdom Energy Statistic2009


22

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 biomass – “Bio-SNG”.

4.2 ‘PURE’ BIOMASS 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 <72 PJ/a <180 EJ/a

Forestry and Agricultural residues

< 60 PJ/a 250PJ/a slated for

electricity

Unknown

Fuels derived from wastes

< 300 PJ/a Unlikely N/A

Table 4-1 Biomass arisings (taken from Thornley et al, E4Tech)

Energy crops are seen to present the largest potential resource amongst biomass fuels internationally,

but considerable uncertainty exists as to the rate at which the market can be developed, and critically in

the sustainability constraints which together with competition for land use will ultimately pose a limit their

development. Nevertheless, the theoretical capacity, globally, to produce energy crops of all types in a

recent study undertaken by E4Tech for DECC is estimated to be in the region of 180EJ per annum. In

the event that this market does develop over the next two decades then UK based companies could

expect to take a share of this resource subject to their ability to pay the landed price of the commodity,

however, the creation of a new global solid biofuels supply business in parallel with an emerging demand

17 e.g.Sustainability constraints on UK bioenergy development - Patricia Thornley a,_, Paul Upham b, Julia Tomei, Energy Policy 37 (2009) 5623–5635 – Tyndall Centre, Manchester University


23

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.670,00019 oven 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.

18 DECC ‐ Biomass supply curves for the UK – E4Tech - March 2009 19 Woodfuel Resource in Britain FES B/W3/00787/REP/2 DTI/Pub RN 03/1436 (2003)


24

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 ‘PURE’ BIOMASS 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 gasification20 of 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% <0.1% Carbon % [DAF] 53.9% 51.4% Hydrogen% [DAF] 6.9% 6.2% Oxygen% [DAF] 33.4% 41.0% Nitrogen% [DAF] 1.0% 0.1% Water % [AR] 16.9% 36 -58% Table 4-2 Comparative properties of wood fuel and a sub-bituminous coal

In addition to these macroscopic properties that govern behaviour of the fuel in the gasifier process

design needs to be informed by an appreciation of the minor constituents in the fuel such as ash chemical

composition, levels of halogens, and volatile metals such as mercury and arsenic. 20 Industrial gasification means the production of syngas to a quality suitable for use in chemical processes.


25

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 species21 and 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 in

2004 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 Section 4.7)

21 Biomass and Bioenergy Vol. 4, No. 2, pp. 103-116, 1993 22 Gill 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


26

Municipal Waste arisings

0

20

40

60

80

100

2005 2010 2015 2020

Mill

ion

Tonn

es p

er a

nnum

Bio Residual Non Bio Residual Recycled

Commercial and Industrial Waste arisings

0

20

40

60

80

100

2005 2010 2015 2020

Mill

ion

Tonn

es p

er a

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 of

facilitating 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. 24 CEN/343 is now mandated for adoption by member states and is available from British Standards Institute.


27

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 in Table 4-3

SRF class and origin Class code : NCV 3, Cl 3, Hg 3

Physical parameters Particle form : Cubes Particle size : Test method: prCEN/TS 15415 Unit Value Test method

Typical Limit Ash content % dm26 14 25 prCEN/TS 15403 Moisture content % ar27 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 parameters Unit Value Test method

Typical Limit Chlorine (Cl) % w/w28 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 15408 Mercury (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 15411 Vanadium (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. 26 dry matter (dm) 27 as received (ar) 28 wet weight (w/w)


28

4.5 TOTAL AMOUNT OF BIOMASS RESOURCE FOR BIO-SNG PRODUCTION

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 ‘PURE’ BIOMASS

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 industry – synthetic 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


29

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 significant

commercial threat to the viability of schemes that utilise such fuels31. 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

29 See BWPI Federation – “Large‐scale biomass threatens 8,700 UK jobs... ...and risks a 1% increase in UK emissions” http://www.wpif.org.uk/Make_Wood_Work_News.asp 30 Coal prices are in the region of £2 per GJ; the price differential to biomass being more than sufficient to purchase 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.


30

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.

32 Conditions 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.


31

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.


32

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 through

to 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 in Figure 5.1 below.

FUEL PREPTHERMO-CHEMICAL

BREAKDOWNINTERMEDIATE PURIFICATION

INTERMEDIATE CONDITIONING METHANATION

POLISHING “PACKAGING”

including COMPRESSION

PRODUCTBio-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 properties – particle size, density, humidity, calorific value, chemical analysis, etc.

34 e.g. NNFCC project 09/008: Review of Technologies for Gasification of Biomass and Wastes: E4Tech June 2009


33

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.

There is extensive expertise in the area of fuel reception, preparation and handling, however, it is a

common location for serious process malfunctions; due diligence experience reveals a consistent and

recurrent problem with fuel preparation, quality and feeding. It is vital, therefore at the design stage to

use proven and reliable designers, and equipment suppliers and to confirm that the process plant will

operate with the particular material specifications envisaged for fuelling the gasifier. Solids handling

systems must be designed in consideration of the particular properties of the materials in question; for

example it would be unwise to assume that woodchip will behave in a handling system in the same way

as wood pellets. CEN/335 goes some way to describing standard test methods that can be employed to

determine the critical handling attributes of particular solid biomass fuels.

5.2 GASIFICATION

There are fundamentally three main types of gasifier:

Fixed bed (down-draft and up-draft)

Entrained flow

Fluidised bed (direct and indirect heating)

Fixed bed biomass gasifiers are used extensively in some parts of the world in small, relatively crude

applications producing a low quality gas for small scale power generation. Fixed bed gasifiers are also

used at a large scale, however, the low carbon intensity of biomass fuels makes them unsuitable for use

in large scale fixed bed gasifiers, unless they are co-fired with coal. On this account it is proposed that

fixed bed gasifiers should be excluded from further consideration where the intent is to produce bio-

syngas at a moderate industrial scale.


34

Figure 5.2 Fixed Bed Gasifiers35 Entrained flow gasifiers represent the state-of–the-art for gasification of pulverised hard solid fuels such

as coal or petroleum coke, or liquids such as residual oils, but are unsuitable for raw biomass or waste-

derived fuels which can not be pulverised in the same manner as coal or coke. However, biomass can be

pre-treated by a process such as Torrefaction, which is in effect a low temperature pyrolysis stage for

manufacturing charcoal. Indeed the Choren Carbo-V gasifier undertakes this reaction within the process,

thereby utilising the energy value of both the volatile carbon that is evolved in a pyrolysis step and the

fixed carbon (charcoal) in an entrained gasification stage – see Figure 5.3. The heat of the gasification

reaction in a gasifier is provided by the oxidation of part of the fuel, and in an entrained flow gasifier the

process is blown with oxygen rather than air. This is essential if it is required to minimise the nitrogen

levels in the syngas, a condition in SNG production that becomes paramount because it is very difficult

(i.e. costly) to separate nitrogen from the SNG later in the process train.

35 Olofsson et al, “ Initial Review and Evaluation of Process Technologies and Systems Suitable for Cost‐Efficient Medium‐Scale Gasification for Biomass to Liquid Fuels” (2005)


35

Figure 5.3 Choren Entrained Flow Gasification system It will be readily appreciated that the pyrolysis and entrained flow gasification steps combine to create a

relatively complex plant, albeit one that is technically demonstrated at a significant scale by Choren. At

this point it should be appreciated that the principal aim of entrained flow gasifier concepts has been to

produce a good quality synthesis gas – a mixture of carbon monoxide (CO) and hydrogen (H2) – and to

present these in a CO / H2 molar ratio that subsequently allows the efficient synthesis of more complex

molecules from these basic building blocks of organic chemistry. An efficient entrained flow gasifier will

produce very low levels of methane in the synthesis gas; methane production requires therefore the

conversion of synthesis gas via a methanation step. This consumes energy and is seen by some SNG

technology developers as a reason to pursue alternative gasification processes that provide a syngas

output that maximises the methane content of the syngas as it is produced from the gasifier.

Fluidised bed gasifiers. Fluidised bed gasifiers exhibit a number of variants – bubbling beds, circulating

beds, indirect and direct heating, pressurised and un-pressurised, air blown or oxygen blown. The

common feature of fluidised bed gasifiers is that they provide a hot aerated bed of granular solid material

into which the granulated fuel is injected. The fluidised bed provides a ”thermal flywheel” whereby heat

transfer from the hot bed material is sufficient to dissociate the fuel into volatile components (syngas) and

ash. The gases are evolved from the top and the ash from the bottom. Conventionally, the heat of the

bed is maintained by burning part of the fuel in the bed itself and the products of combustion (water and

some carbon dioxide) are evolved with the syngas.


36

Figure 5.4 Fluidised Bed gasifiers (Direct and Indirect)

When the intent is ultimately to produce pipeline quality SNG it becomes necessary to use pure oxygen

for the gasifier in order to eliminate nitrogen from the resulting syngas, however, the cost of the

associated air separation unit that produces the oxygen represents a considerable burden on the plant

economic case. This has provided the incentive to develop new fluidised bed concepts in which the plant

is configured in such a way as to allow air firing to heat the bed material outside the gasification reactor –

the so called indirect fluidised bed gasifiers. Indirect fluidised bed gasifiers also tend to produce a

significant quantity of methane in the syngas, however, it must be appreciated that indirect gasifiers are

still in development. To the extent that the syngas can be produced with a significant methane content

this represents a potential improvement in overall fuel energy conversion efficiency. The quest for a

significant methane content in the syngas has informed research and development into new gasification

concepts, notably indirect fluidised bed systems. These have the potential to achieve methane in syngas

levels in excess of 10%, thereby offering the promise of slightly improved overall SNG yields36. It should

be appreciated, however, that methane produced in this way does not come alone; it is accompanied by

other longer chain alkanes and with a higher level of tars in the syngas. These need to be removed from

the gas stream and represent in their own way a potential energy loss from the system.

High pressure operation also favours the direct production of methane in the syngas, and there is already

some experience with the operation of pressurised fluid bed gasifiers such as the high temperature

Winkler process or HTW. The HTW gasifier has operational experience co-firing waste derived fuels with

pure biomass and at pressures of 30 bars at which a methane-in-syngas level of 8% (dry basis) can be

achieved.

36 This is because 10% of the gas production does not need to be converted to methane via the exothermic catalytic reactions required to reform synthesis gas – CO and H2


37

The choice of a gasification technology therefore hinges around these variants:

The use of an entrained flow gasifier fuelled by torrefied biomass37

An oxygen blown fluidised bed38

An oxygen blown pressurised fluidised bed39

The selection of the Choren Carbo-V gasifier, or similar (N.B. oxygen blown)

An indirect fluidised bed40.

These process choices are nevertheless uninformed by any commercial considerations. The use of

waste-derived fuels, even in co-firing with clean biomass has a significant and beneficial effect on the

overall cost effectiveness of Bio-SNG production. This is a strong incentive to select a gasification

technology that can accept waste-derived fuels; hence process selection is biased towards the choice of

fluidised bed gasification; entrained flow gasifiers being unsuited to such fuels.

In identifying a development pathway for the production of Bio-SNG Progressive Energy is inclined to the

view that selection of an indirect gasifier technology may not be an optimal course of action. Firstly the

possible prize, a slight increase in the overall efficiency of SNG production, may be insufficient

justification for delay in securing a market position that may arise from the relative novelty of this

technology. Secondly, efficient heat recovery from the gasifier and gas processing train can be used to

create non-fossil electricity which as an output is at least equal in value to Bio-SNG. Table 5-1illustrates

the key factors in this judgement where real world deliverability needs to be set against the theoretical

benefits of yet to be realised technical developments. Process choice, therefore should favour an oxygen

blown fluidised bed, and perhaps, if commercially justifiable the pressurised41 oxygen blown fluidised bed

gasifier, such as the HTW or pressurised HTW.

There will be some variability of the syngas quality produced by the gasifier options discussed briefly

above, notably with respect to the tar loading in the raw syngas; with an entrained flow gasifier offering

the best quality on account of the intrinsically higher temperatures reached in such reactors. This is an

advantage but not necessarily a decisive advantage over fluidised bed systems; the gas cleaning

processes downstream should, in any event be designed to cope with a range of syngas qualities.

Beyond considerations of tar loading in the synthesis gas the next most sensitive issue for Bio-SNG

production is the presence of nitrogen. Nitrogen can be produced through fuel-bound nitrates and via the

residual levels of nitrogen to be found either in oxygen used in the gasifier or via the circulating bed

material within an air-blown indirect gasifier. In either case, a small amount of nitrogen passing through

37 Potential suppliers / technologies here include Udhe / Prenflo gasifier, and Choren entrained flow gasifier 38 Potential suppliers include Foster Wheeler, and Thyssen / HTW, Enerkem 39 Potential supplier would be Thyssen / pressurised HTW 40 Potential supplier Austrian Energy / indirect CFB, future development of indirect fluid bed by ICN. 41 It is more energy efficient to compress SNG than syngas and water vapour, therefore the process pressure is most efficiently provided by high pressure gasification, followed by further SNG compression for export.


38

the system could reduce the Wobbe Index or Calorific value of the resulting Bio-SNG below the GS(M)R

limits for pipeline quality. This is a key issue that would require resolution as part of the selection and

specification process for a gasification technology.

Approach

No penaltyfor oxygen

production

Methane content ex gasifier

Provenat substantive scale

Deployable at m

oderatescale

Deployable at large scale

Fuel preparation

Track record on waste fuels

Options to m

inimise

pressurisation loads

Tarsex unit

Chem

ical Contam

ination

Indirect gasification - -Direct gasification (fluidised bed) -Entrained flow -Pyrolysis to bio-oil -

Table 5-1 Technical ideals and commercial reality

Gasification of wastes: It should be appreciated that for a considerable period of time the pursuit of the

gasification of wastes has been focussed in the main not on the production of a quality syngas but in

pursuit of the following:

To assure destruction of hazardous chemicals at extreme temperatures

To produce fused ash streams in which heavy metals may be trapped

To take advantage of particular support mechanisms (e.g. the Renewables Obligation)

In an attempt to give lower emissions to the environment than conventional waste incineration

Accordingly it is important to understand that the technologies that are targeted at these objectives are

not necessarily focussed on the efficient production of a high quality syngas, which would be the over-

riding objective of a gasifier producing syngas for Bio-SNG synthesis. Hence waste gasification systems

are in general unsuitable for this application. The HTW gasifier has, however, a track record of successful

operation with waste-derived fuels42. Relevant examples of gasification projects are shown in Appendix

1.

42 The British Gas ‐Lurgi (BGL) fixed bed slagging gasifier at Schwartezepumpe had also some considerable operating experienced with waste derived fuels, but only when co‐fired with >70% coal.


39

5.3 GAS PROCESSING

Syngas processing requirements are determined by the gas quality limitations imposed by catalysts used

in the methanation reaction. The methanation reactions are moderately exothermic and simply

represented as follows:

CO + 3H2 → CH4 + H2O - 217kJ/mole…………………… (1)

C02 + 4H2 → CH4 + 2H20 - 175kJ/mole……………………. (2)

The reaction takes place at elevated temperature over a catalyst, for which there are a number of material

options including nickel, iron, chromium and copper based catalysts, however, these are invariably

intolerant of even traces of heavy metals such as mercury, lead and arsenic and intolerant of small

particles of tar, or of sulphur and chlorine compounds. The main technical challenge posed by an SNG

facility is therefore the syngas cleaning that is required upstream of the methanation reactor.

Figure 5.5shows the practical scale of syngas quality improvement that must be achieved to enable

satisfactory catalyst life to be achieved.

0

2

4

6

8

10

12

14

16

Tars Particulate Sulphur Halides

Contam

inen

t mg/Nm3 gas

0

500

1000

1500

2000

2500

3000

Tars Particulate Sulphur Halides

Contam

inen

t mg/Nm3 gas

Raw Engine Synthesis

Figure 5.5 Syngas quality ex-gasifier, requirement for use in engine and for synthesis

State-of–the-art gas processing technologies are capable of achieving the necessary syngas quality, the

challenge being to do this economically on a process plant of relatively modest scale and at a reasonable

level of energy efficiency. The syngas leaving the gasifier will be at temperatures around 9000C and will

carry therefore a significant amount of sensible heat; this should be recovered efficiently for the

generation of steam for use in the process and for power generation to meet plant electricity demand.


40

Heat recovery from the hot syngas is straightforward, however, at temperatures below 300oC tars begin to

condense with the consequent risk of fouling, therefore direct heat recovery from the syngas should be

terminated at this temperature. Most gas cleaning techniques will require the syngas to be at a moderate

temperature, hence heat recovery and process re-heating form an important part of the process train

design.

Contaminant removal Non-volatile particulates (ash and char) should be separated by means of conventional processes such

as cyclones and hot gas filters at a temperature above the tar dew point, in order to avoid fouling with

condensing tars. Thereafter syngas cleaning would most probably involve gas scrubbing in contact with a

liquid scrubbing medium. Conventionally syngas scrubbing would be via water based systems whereby

gas/water contact removes fine particulates and tars and provides a medium for the neutralisation and

absorption of incidental products of gasification such as HCl and ammonia. Importantly, the gas

scrubbing system needs to reduce the syngas temperature below the dew point of the lightest tar

fractions; this will also remove mercury vapour from the gas. The use of water based systems, however,

creates a large water demand, and a significant water treatment and waste water discharge burden. Oil

based syngas scrubbing techniques have been developed which can give effective tar and particulate

removal thereby offering the opportunity to reduce the significant penalties associated with tar scrubbing

via water-based scrubbing systems. Following the core gas scrubbing operations it will probably be

necessary to undertake further syngas cleaning steps to achieve the gas purity levels demanded by the

catalysts. This is a subject for detail design and specification to be derived via discussions with the gas

processing contractor and catalyst suppliers, but will involve guard filters and beds to polish the gas and

guard against process upsets.

Hydrogen / Carbon Monoxide Molar Ratio adjustment Depending upon the performance of the gasifier and the chosen process configuration it will be necessary

to introduce a processing step to adjust the ratio of carbon monoxide to hydrogen in order to arrive at a

favourable molar ratio of hydrogen to carbon monoxide for the methanation reaction (Equation 1) above.

This is conventionally undertaken at high temperature over a catalyst (the water gas shift reaction) for

which similar gas quality criteria would apply as for the methanation reaction itself; however some WGS

catalysts are tolerant to sulphur. Given that the syngas will contain a level of hydrogen sulphide produced

in the gasifier, and which would not be removed in the upstream gas cleaning process it is proposed that

a sour WGS catalyst should be considered for incorporation into the design43. In the water gas shift

reaction carbon monoxide in the syngas is reacted with steam to produce hydrogen and carbon dioxide:

CO + H2O → H2 + CO2………………………………(3)

43 It should be appreciated, nevertheless, that not only are sour shift catalysts tolerant of hydrogen sulphide, they do in fact rely upon a certain level of hydrogen sulphide in order to work. The threshold value of hydrogen sulphide is 100ppm(v), a level that can readily be obtained with the sulphur levels existing in biomass or waste‐derived fuels. Nevertheless the fuel specification needs to ensure a certain minimum level of sulphur if a sour shift catalyst is employed.


41

It will be readily appreciated that the water gas shift reaction can be used to trim the relative CO / H2

concentrations in the syngas. The water gas shift reaction is strongly exothermic and the heat of reaction

can be used to assist in returning the syngas to the temperatures required for the methanation reaction to

take place – in the range 6000C >3000C.

Following the WGS the syngas would have the appropriate molar balance for the methanation reaction.

Some methanation process configurations however combine the shift and methanation catalytic reactions

wherein simultaneously with the occurrence of the shift reaction in the combined reactor system, carbon

monoxide and hydrogen are converted to methane and water. Steam formed by the methanation reaction

promotes the shift reaction to in turn, produce the hydrogen necessary to carry out the methanation

reaction. Elegant though this process arrangement appears to be, any hydrogen sulphide in the syngas

will poison the methanation catalyst. It follows that the hydrogen sulphide must be removed from the

synthesis gas following the WGS reaction and before methanation.

Removal of H2S and CO2: There are several proprietary systems for removal of either of these gases, however, a single process

that could remove both would be based upon physical absorption via e.g. a tertiary alcohol or a

proprietary solvent such as Selexol or Rectisol. Given the sensitivity of the downstream methanation

catalyst to sulphur poisoning it may be necessary to specify a multistage system. Depending upon the

vendor’s guaranteed performance it would be prudent to incorporate a solid state (ZnO) scrubber to guard

against any residual carry-over of H2S.

In principle the separated biogenic CO2 could be vented to atmosphere without incurring any GHG

penalty, however, subject to the development of appropriate industrial infrastructure it would be prudent to

consider the scope for compression and export of this gas for geological storage or enhanced oil recovery

(EOR).The capture of small amounts of H2S represents a considerable nuisance as well as a hazard.

With sulphur levels as they are in biomass fuels there is insufficient sulphur to warrant a conventional

elemental sulphur recovery plant such as the Claus process so it may be appropriate to incorporate a

biological system such a Thiopaq for the recovery of elemental sulphur. (This is a particular example of a

case where development at a moderate scale imposes economic burdens on the process. It is also an

example of why it is necessary to specify and control the properties of the fuel that can be accepted into

the plant.)

5.4 METHANATION

Methanation of syngas is an established process, and is not specific to bio-gases, nevertheless the

optimisation of the process design with respect to energy efficiency (esp. heat recovery and minimising

compression power) will be a significant process engineering exercise. Conventionally the methanation


42

reaction will take place over a three stage process in cylindrical vessels packed with 6mm diameter

sintered catalyst beads. Flow in the reactors may be radial or axial, but the critical design consideration is

the control of heat release in the catalyst bed in order to prevent catalyst de-activation at high

temperatures that may be obtained through the exothermic reaction. Catalysts may also be deactivated

by sulphur and chlorine compounds and by a low carbon monoxide to hydrogen ratio leading to elemental

carbon deposits. The methanation of synthesis gas will consume approximately 20% of the energy

potential of the gas, hence it is vital to ensure efficient recovery and use of this energy.

Process intensification Process intensification holds the promise of achieving in small facilities the economies of scale normally

associated with large industrial facilities. A notable development in this area is the micro channel Fischer

Tropsch reactor that has been developed by Oxford catalysts for the synthesis of higher alkanes from a

natural gas feedstock, following steam reformation and WGS. The viability of this process at moderate

scale results from the significant reduction in the number of process vessels and heat exchangers, piping

and controls required, along with the high reaction rates and efficient heat recovery afforded by the micro-

channel concept. Discussions with Oxford catalysts established that there is every reason to expect that

the micro-channel reactor concept could be effective in the production of Bio-SNG. The proof and

demonstration of this, however, would entail considerable expense and a development programme of at

least two years. A balanced judgement therefore would be that the micro-channel reactor may well have

some merit for a future application, but in the meantime the use of conventional catalytic reactors is

feasible and carries no serious economy of scale disadvantage when deployed in a moderately sized

facility. Finally, micro channel reactors are likely to be even less tolerant than conventional catalytic beds

of contaminants in the gas stream.

5.5 GAS CONDITIONING, COMPRESSION AND METERING

The Bio-SNG emerging from the methanation process will be saturated with water vapour and contain a

small amount of un-reacted hydrogen and of elemental nitrogen that originates from the 98% pure oxygen

used to fire the gasifier and from fuel-bound nitrates. The achievement of pipeline quality gas would allow

a small proportion of nitrogen, provide that the gas was substantially free from other inerts, apart from the

inevitable loading of noble gases (He, Ar etc.). The optimisation of process design must include an

assessment of the balance of advantage to be struck between the required level of oxygen purity, the

likely levels of fuel bound nitrogen and the possible propane dosing requirements that might be required

to achieve the GS(M)R specification requirements for Wobbe Index and Calorific value.

The methanation process will not achieve 100% conversion of the hydrogen from the syngas and is likely

to exceed the GS(M)R pipeline specification regarding hydrogen content (<0.1% molar) without a further

processing step. It is conceivable that trimming the hydrogen content could be achieved by blending with


43

pipeline gas, or by membrane separation; however, it is suggested that the specification should be

questioned to see if a slightly higher hydrogen content could be accepted.

Compression to export pressure will depend upon where the gas is to be injected (National grid and/or

the LDZ). Clearly, on account of the energy requirements associated with compression, the lowest

pressure option will give the greatest process efficiency. This could be a significant feature of Bio-SNG

plant location. Before the Bio-SNG could be exported via the gas network it would require odorising.

On account of commercial uplifts that would be necessary to make Bio-SNG viable, fiscal quality metering

will be required along with sampling and quality assurance for biogenic carbon content. Where waste-

derived fuels have been used then the only practical method of the determination of the proportions of

fossil / bio carbon is via a method based upon C14. The fundamental principles of this technique are

currently under a process of accreditation with Ofgem in connection with electricity generation from

biomass.

5.6 CONCLUSIONS ON PROCESS AND TECHNOLOGY The following key conclusions can be drawn:

Systematic understanding and control of fuel properties is vital.

Bio-SNG can be produced from existing state-of-the-art process plant; the main technical risk

being associated with first-of-a-kind process integration issues. This becomes then a risk

management and project finance challenge rather than an RD&D exercise.

Indirect gasifiers may give a marginally greater direct production of methane (>10% cf <8%),

however, pressurised fluid beds have been demonstrated at an appropriate scale, require no

further development and are being deployed by others for the production of bio-syngas. The

slight differential in direct methane production can be compensated for by the efficient recovery

and valorisation of heat from the process.

Gas processing technologies exist and some relatively new processes such as oil based system

offer the opportunity to reduce water consumption and effluent quantities.

The may some merit in seeking a derogation of GS(M)R specifications regarding hydrogen

content.

Pipeline injection should be at the lowest pressure possible, consistent with capacity of the gas

export system from that point.


44

6 Economic Assessment

Using best available information, the economic profile of bio-SNG projects is considered. Evaluation of

process economics is critically dependent on input assumptions. This builds on the technical review,

along with a perspective on costs and impact of existing, and proposed incentives. Plant economics for

such capital intensive processes are dependent on the state of the market, and costs associated with risk

transfer for equipment supplied under EPC contract structures. Similarly, the emergent state of the

biomass market supply chain, along with competitive uses, means that biomass fuel resources will be

volatile. Therefore appropriate sensitivity analyses are undertaken. Against these scenarios, the potential

project returns are evaluated. This review also compares (at a high level) the returns for a gasification

facility producing power.

This analysis assesses the cost of carbon abatement via this route, when compared with alternative direct

uses of biomass for heat and electricity as well as other carbon abatement approaches.

6.1.1 Scale and operational assumptions Two representative scales have been assessed; a small, demonstration scale facility requiring ~100,000

te pa of feedstock and a larger commercial facility of requiring ~600,000 te pa . These are outlined in

Table 6-1. It is assumed that the process operates at a pressure which matches grid injection such that

downstream compression requirements are limited. Here it is assumed this would be 20bar, so would be

suitable for intermediate or high pressure distribution level injection but not NTS without further

compression. This assumes therefore that the gasifier operates at the appropriate pressure to account for

pressure drops in the gas processing train (typically ~20% from gasifier to exit of methanation reactor, ie

gasification at ~26bar)

Whilst the facility does generate electricity recovered from the high grade heat, at the assumed SNG

efficiency, the heat suitable for power production is assumed to compensate for the parasitic loads,

including the ASU load (separation, oxygen compression) and sufficient CO2 compression for lock-

hopper inert blanket. In the event that an indirect gasification configuration is used, there would be no

ASU load, although it is likely that the system would operate at low or atmospheric pressure, therefore

impose syngas compression loads. Therefore it is assumed in either case there is no excess electricity for

export.


45

Parameter Small Large Input Energy rating (energy per hour) 50MWth (180GJ/hr) 300MWth (1080GJ/hr) Input fuel energy per annum 0.4TWhth (1.3PJ) 2.4 TWhth (8.6PJ) Biomass fuel (pellets, 16GJ/te) pa 81,000 te pa 486,000 te pa Biomass fuel (Woodchip, 13GJ/te) pa 100,000 te pa 600,000 te pa Solid Recovered fuel (18GJ/te) te pa 72,000te pa 432,000 te pa Operation Load factors (hrs pa) 7200 7200 Baseline Efficiency to SNG44 65% 65% Output Bio-SNG MWth 32.5MWth 195MWth Bio-SNG GJ/Hr 117 702 Bio-SNG therm/hr 1110 6,650 Bio-SNG Nm3/hr 3330 20,000 Bio-SNG energy per annum 0.23 TWhth (0.84PJ) 1.40 TWhth (5.05PJ) Equivalent Households ~15,000 ~100,000 Equivalent Passenger Vehicles ~25,000 ~150,000 Comparative Electrical facility (no SNG) 12MWe (24%

efficiency assuming gas engines)

90MWe (30% efficient based on an IGCC configuration)

Table 6-1 Project scale and output assumptions

6.1.2 Investment Cost assumptions As discussed previously, there are currently no commercial scale Bio-SNG facilities in operation, and

there is only a limited number of biomass gasification facilities which create a syngas of sufficient quality

for catalytic conversion, with still fewer operating on waste derived fuels. Therefore investment cost

assumptions are estimates, however these are sufficient to enable an understanding of the economics of

the process, given that even estimates from suppliers are only +/-30% after a formal engineering study.

The following investment costs are dominated by the capital costs of the materials handling, gasifier, gas

processing, methanation and conditioning for injection. The costs also allow for utilities and services,

including grid/gas connection and indirect costs (design, development, construction

management/commissioning and contingency).

The cost of performance guarantees being provided by an EPC cannot be readily ascertained at this

stage, as they will depend on both the detailed requirements of the funder, and also the EPC’s appetite

for the sector combined with the ability to cascade the guarantees down the supply chain. Such

guarantees would form part of detail project negotiations, and are not included here. Final out-turn costs

are a function of the final design, the financing route and cost of risk transfer as well as general economic

issues including exchange rates, appetite for an EPC contractor to undertake the work and competition

for supply in a sector with an immature supply chain. The cost estimates below are developed using the

a range of data sources: 44 Based on Pellets or SRF. Where the fuel has higher moisture content (eg woodchips, modelled here at 25%), the total efficiency can be higher when low grade waste heat is utilised to pre‐dry the fuel prior to gasification. 65% is considered a credible conversion efficiency using existing gasifier and methanation combinations.


46

Choren Choren has a 50MWth (input) facility operating in Freiburg (shown in Appendix 1). This is based on an

entrained flow gasifier reconfigured for operation on 100% biomass (woodfuel). This facility is designed to

manufacture Syngas for conversion to BTL in a Fischer Tropsch reactor. The gasification train for this

facility has been completed and operated, with the F-T stages undergoing commissioning since mid 2010.

This is a facility which must provide a similarly high level of contaminant-free syngas to that demanded by

Bio-SNG. Choren estimate that the total investment for a 50MWth facility to produce hydrogen to be

67MEuro (£56M)45. Whilst this is clearly only an estimate, their experience at Freiburg will valuably inform

this figure, and it is a sound basis for the current cost for an entrained flow wood gasification system to

produce high quality hydrogen. Choren indicated an assumption that a Bio-SNG facility would be

90MEuro (£75M), although they have no direct experience on this processing stage. Progressive Energy

is of the view that this addition for a methanation reactor is probably overly conservative, given that the

Hydrogen system will already have full shift reactors, sulphur removal, CO2 removal, and a high quality

syngas stream.

GobiGas This facility is being built in two phases, both fuelled by wood pellets. The first phase is 32MWth (input)

based on indirect gasification (Repotec technology as used in Gussing), costing £75M (based on

contracting in 2010 for completion in 2012), although this is integrated with a district heating system. The

second phase at ~120MWth (input) designed to produce 80MWth Bio-SNG is anticipated to cost £150M,

but is not expected to commence build until 2015.

Enerkem Enerkem is one of the few gasification companies successfully pursuing the gasification of waste using a

fluidised bed gasifier, to syngas of sufficiently high quality to convert catalytically to a biofuel. They have

a small scale (8MWth) facility fuelled by waste wood and are currently developing two municipal waste

facilities at 50MWth in Edmonton, Canada and Mississippi, US (shown in Appendix 1). These are

reported to cost $CAN80M (£50M) and $US140M £88M) respectively, with the latter encompassing the

MSW pre-processing facility from raw waste. Whilst the outturn product is bioethanol, and not Bio-SNG,

both processes demand high quality, preconditioned syngas and catalytic reactor stage, and therefore the

costs are anticipated to be similar to that expected for a Bio-SNG plant.

The assumed investment cost for a 50MWth plant is ~£65Million (2010) for a wood based facility. The

experience with waste gasification is even more limited, and different facilities often have substantially

different design intents (waste destruction through to efficient energy recovery). However, there are a

number of reasons why waste gasification is more challenging; the fuel is heterogeneous and therefore

may need enhanced material handling; the nature of waste imposes requirements on the gasification unit

itself; the fuel contains a wider range of chemical contaminants and therefore the gas processing must

45 Choren, Personal correspondence, June 2010


47

handle this46; the risk margins demanded to cover the reduced experience. Therefore, for this analysis it

is assumed that a waste-based system (assuming offsite preparation of the MSW to SRF) will cost 15%

more than the pure biomass one, ie £75Million (2010). For a 300MWth (input) facility, the assumed

investment cost is £215M and £250M, for pure biomass and waste fuel facility respectively. Figure 6.1

shows the breakdown of costs for such a facility. Given the nature of these estimates, it is important to

undertake a sensitivity analysis of at least +30% in the downside case, recognising both the

underestimate in the baseline figures, and also the requirement for provision of performance risk

management within an EPC. It must be noted that whilst ‘learning’ is often cited as a reason that

subsequent projects achieve a lower cost, Progressive is of the view that in novel projects such as these,

initial costings on early projects (ie prior to build) are typically underestimates of the final outturn costs,

negating any learning effect on early follow-on projects. At this stage it is presumed that the project will

not be leveraged at the outset (although there may be opportunity for refinancing after a track record of

successful commercial operation). The build time is assumed to be 3 years in both cases, although it may

be feasible to construct the smaller facility in a shorter period of time given substantial offsite manufacture

of components.

Assumed investment cost Small (£000) Large (£000) Energy rating (energy per hour) 50MWth 300MWth Pure biomass £65,000 £215,000 Waste Fuel £75,000 £250,000

Table 6-2 Investment cost assumptions

Solid handling & Prep

Gasification

Syngas processing

Methanation, Conditioning

Utilities, services,

connections

Indirects & Contingency

Figure 6.1 Cost breakdown of major components (Large SRF facility)

46 Recognising however, that the most challenging part of the gas processing is not the bulk contaminant removal, but the final ppm and ppb removal demanded by the catalysts, which is common to both biomass and waste fuels)


48

6.1.3 Operating Cost assumptions The basic cost assumptions are shown in Table 6-3, based on industry norms and specific information

relating to the feedstock type. The capital cost assumptions have assumed oxygen is supplied ‘over the

fence’, although in line with the efficiency assumptions, it is presumed that power is supplied FoC to the

provider (ie no benefit is taken on the revenue side from power generated). This may not be the out-turn

commercial configuration, but ensures that the oxygen cost base is fully accounted for.

Costs £000s Small (£000) Large (£000)

Fixed costs Labour,

Maintenance

Insurance

Land Lease

Rates, permitting, Monitoring, Connections

Total

£1,000

£1,300

£400

£100

£500

£3,300

£1,000

£4,300

£1,300

£200

£1,500

£8,300

Oxygen (over the fence with power supplied FOC)

£650

£25/te excl

power (3.5te/hr)

£2,300

£15/te excl power

(21te/hr)

Consumables £250 £1,000

Consumables SRF £500 £2,000

Disposal costs biomass £0 £0

Disposal costs SRF £600

£40/te & 15,000

te pa (20% ash)

£3,600

(£40/te & 90,000

te pa (20% ash)

Total Biomass £4,200 £11,600

Total SRF £5,050 £15,200

Table 6-3 Operating Cost assumptions

6.1.4 Feedstock

SRF Woodchip Pellet 18 GJ/te

60%energy Bio 13 GJ/te

100%energy Bio 16 GJ/te

100%energy Bio -£27/te £65/te £112/te

-1.5 GJ/te 5.0 GJ/te 7 GJ/te Table 6-4 Feedstock Assumptions


49

The biomass feedstock assumptions are shown in Table 6-4. These figures are based on a variety of

sources:

The SRF data is based on knowledge of the industry for contracting SRF of this type of biogenic content.

This is fuel which has been processed using biological drying. It must be noted that an SRF produced via

autoclaving would have a high biogenic content, but the energy penalty and therefore cost of processing

will be significantly higher.

Woodchip. There would probably need to be an onsite drying facility for woodchip, which would entail

additional investment cost, opex and electrical loads, although it is possible to use low grade heat for

drying which might not otherwise be usable. However assuming a fuel price based on energy content

(NCV), the additional drying using otherwise wasted heat is increasing the relative efficiency of the facility.

In this analysis, this is assumed to compensate for the necessary drying investment and operational

costs. The price assumption in Table 6-4 is from DECC’s biomass fuel cost for large scale fuel

generators, produced for the RHI evidence base47.

Pellets command a significantly higher price than woodchip; this is a function of both the higher

processing cost (energy required for drying to 10% moisture at the point of manufacture, along with the

electrical loads for hammer-milling and pelletising) as well as the enhanced out-turn product value due to

the enhanced fungibility compared with woodchip). .Again figures are taken from DECC’s analysis.

Waste wood may offer an alterative, feedstock, having a biogenic content of ~90% by energy. The plant

would need to handle contamination with the same degree of robustness as the SRF facility, and

therefore would need to assume the same capital cost as the SRF facility. However, the ash disposal cost

would be lower. Initially the cost of the feedstock would be substantially lower than virgin biomass,

potentially at zero cost or even with a small gate fee. However the expectation is that feedstock cost

would increase substantially over time as demand for biomass increases and biomass combustion

facilities are constructed with the capability of co-firing waste wood with pure biomass. Securing waste

wood of this quantity would be challenging. Therefore, whilst this could be a useful interim fuel, it has not

been assumed as a base-case fuel.

The DECC analysis does not provide predicted outturn prices for bulk biomass for 2020, although

interestingly for biomass heating applications, biomass prices are assumed to decrease relative to fossil

fuels over a 2020 time frame. This is unlikely. In this analysis it is assumed that the escalation for

biomass is the same as for natural gas. This is a rationale assumption since the price will reflect, as a

minimum the fuel which is being replaced. Arguably as the price of carbon impacts then the value of low

carbon fuels may even increase faster than higher carbon intensity fuels.

47 Biomass prices in the heat and electricity sectors in the UK For the Department of Energy and Climate Change January 2010 Ref: URN 10D/546 (Feb 2010)


50

6.1.5 Revenue Assumptions The Level of the RHI is yet to be formally determined, but the February 2010 consultation document

indicated a value of £40/MWh for biogas injection. It has been mooted that this figure may rise to

£50/MWh although this is uncertain, so is considered as a subsequent sensitivity case.

As discussed, in this analysis, it is assumed that there is no residual power after servicing parasitic loads,

including oxygen demand but there will be low grade heat. However, it cannot be assumed this can be

sold in significant quantity, so is not considered in the base case. The impact of such sales, are however

explored as a sensitivity to the outturn price of Bio-SNG

6.2 LEVELISED COST ANALYSIS A levelised cost analysis has been carried out using these assumptions to determine the cost of Bio-SNG.

The base case discount rate has been assumed to be 12%48, with and a three year build. The costs are

all (2010 prices) and are shown real, and assume no escalation over RPI for each component. DECC

June 2010 data indicates a 2010 natural gas wholesale price of 59p/therm. The charts below show a

more realistic current band of natural gas prices of 40-60p/therm.

This analysis demonstrates that without the RHI, at the scales considered, Bio-SNG will not be feasible.

The disparity between the Bio-SNG cost and the wholesale Natural gas price is significant.

With the RHI, this analysis demonstrates that at the small scale, it is uneconomic to produce Bio-SNG

relying only on the slated RHI support level of £40/MWh. For a project of this scale RHI support would

need to be at least twice as high for the Bio-SNG to be competitive with natural gas. Alternatively, capital

grant support would need to be of the order of £35-45Million for either the SRF or woodchip facility to be

competitive.

At the larger scale, and with the currently proposed RHI support level, the SRF fuelled facility looks to be

competitive with natural gas, and if woodchip could be sourced at 5/GJ the cost of bio-SNG from imported

and indigenous woodchip could be close to competing at the upper band of gas prices. Operation on

wood pellets looks to remain uncompetitive even at this scale.

By way of comparison, this is not dissimilar from analysis of bio-SNG in the RHI documentation presented

by NERA (February 2010), after accounting for the increased scale in the NERA analysis, and combined

biomass-waste fuels.

48 In reality an early project would demand a higher discount rate reflecting the risk profile (maybe up to 15%, but a mature technology might allow a lower discount rate say ~10%.This is also a function of the investors appetite for risk in evaluating investment.


51

It must be noted that this analysis is a calculation of the levelised cost at a discount rate of 12% in order

to calculate an out turn cost of Bio-SNG. For an investor to have the appetite to invest, then there must be

a sufficiently attractive return. From this analysis it is clear that the only case which could have sufficient

scope for project return is a facility fuelled by SRF. On the assumption set given here, such a facility

provides a pre-tax unleveraged return of 14.5% to 17% for gas prices of 40 to 60p/therm respectively.

However, whether this is a sufficient return to entice investment depends on the risk profile, its

management and perception of ability to secure debt on refinancing in order to enhance the project value.


52

0

30

60

90

120

150

180

210

240

270

300

330

SRF Woodchip Pellet

Net cost of Bio‐SNG (p/therm)

Levelised Cost of Bio‐SNG Without RHI

Small Large

TypicalNatural Gas prices range

Figure 6.2 Levelised Cost of Bio-SNG without RHI (p/therm)

0

30

60

90

120

150

180

210

240

270

300

330

SRF Woodchip Pellet

Net cost of Bio‐SNG w

ith RH

I at £40

/MWh (p/the

rm)

Levelised Cost of Bio‐SNG With RHI at £40/MWh

Small Large


Figure 6.3 Levelised Cost of Bio-SNG with RHI at £40/MWh (p/therm)


53

0

10

20

30

40

50

60

70

80

90

100

110

SRF Woodchip Pellet

Net cost of Bio‐SNG w

itho

ut RHI (£/M

Wh)

Levelised Cost of Bio‐SNG without RHI

Small Large


Figure 6.4 Levelised Cost of Bio-SNG without RHI (£/MWh)

0

10

20

30

40

50

60

70

80

90

100

110

SRF Woodchip Pellet

Net cost of Bio‐SNG after assum

ed RHI (£/M

Wh)

Levelised Cost of Bio‐SNG without RHI

Small Large


Figure 6.5 Levelised Cost of Bio-SNG with RHI at £40/MWh (£/MWh)


54

6.3 SENSITIVITY ANALYSIS

The figures below show how the levelised cost is made up for the large scale project.

0

10

20

30

40

50

60

70

Cost per M

Wh (£/M

Wh)

Levelised Cost Breakdown Large SRF facility

Bio‐SNG

Incentive

Fuel

Opex

Capex

Figure 6.6 Levelised Cost Breakdown for Large SRF fuelled facility (RHI at £40/MWh bio)

0

10

20

30

40

50

60

70

Cost per M

Wh (£/M

Wh)

Levelised Cost Breakdown Large Woodchip facility

Bio‐SNG

Incentive

Fuel

Opex

Capex

Figure 6.7 Levelised Cost Breakdown for Large Woodchip fuelled facility (RHI at £40/MWh bio)


55

Figure 6.6 & Figure 6.7, show the cost breakdown (£/MWh) for the large facilities. When fuelled by

woodchip, the capital cost and the biomass costs are both similar, and dominate over the operational

cost. At £40/MWh, the RHI is substantially more significant than either the capital or feedstock elements.

When fuelled by SRF, the capital cost dominates, since the fuel is no longer a cost but provides a small

contribution to the revenue stream. In this case, the lower biogenic fraction reduces the value of the RHI,

and although this is still an important factor in viability, the SRF case will be slightly less sensitive to the

absolute level of the RHI.

6.3.1 Escalation The above analysis is “real” and considers 2010 gas prices. In the future, gas prices are likely to escalate

at a different rate from inflation, as may biomass prices. In its analysis for the RHI (February 2010)DECC

does not attempt to consider wholesale biomass prices out to 2020 for the purposes of large scale power

generation “The prevalence and preference for long term contracts, with companies establishing bilateral

contracts with suppliers, makes it difficult to establish a clear relationship between price and feedstock costs. There are also far more feedstock types, and fewer generators in the electricity sector, hence a typical supply chain could not be constructed. Furthermore, it is more uncertain how this sector will develop in the future.”

Progressive Energy is of the view that biomass prices are likely to move at least in line with natural gas

(and may possibly increase faster if the pressure on biomass resources increases both in the UK and

internationally). This does conflict with the prevailing DECC view which believes biomass will become

cheaper relative to natural gas. Clearly DECC’s position would indicate a long term decrease in Bio-SNG

outturn cost compared with prevailing gas prices, and therefore improvements in the economic outlook for

a project.

However, even if biomass prices were to increase in line with natural gas, and other costs were to remain constant, the price of SNG would reduce relative to natural gas since the feedstock only represents ~50%

of the production cost. For example, using DECC’s central case, natural gas is believed to increase by

15% by 2020 (in real terms) to ~68p therm. This would result in only an ~8% increase in the Bio-SNG

price ie 67p/therm for the woodchip case. However using DECC’s “high” case, natural gas would

increase by 50% in real terms, resulting in only a 25% increase in the Bio-SNG Cost to 77p/therm

compared with a natural gas price of 97p/therm, ie still improving the economic outlook for Bio-SNG.

In reality the non-feedstock costs (investment and operational costs) are also likely to increase to a

degree (in light of prevailing energy price increases and an international appetite for low carbon projects),

somewhat softening this improvement.


56

6.3.2 Impact of capital Cost, Opex, Fuel price, RHI and heat sales

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

Base Capex +30% Opex +30% Fuel +£1.5/GJ Fuel ‐£1.5/GJ RHI £50

Net cost of Bio‐SNG after assum

ed RHI (£/M

Wh)

Senstivity Analysis for large facility

SRF Woodchip

Figure 6.8 Sensitivity analysis for large scale facility fuelled by SRF and woodchip.

Capital cost: As shown in Figure 6.8, an increase in capital cost of 30% would be significant for both

facilities, although as a proportion of the base case Bio-SNG price has a proportionately higher impact for

SRF. However, an SRF facility might still provide an acceptable outturn bio-SNG cost, whereas a

woodchip fuelled facility would not be feasible at the gas prices considered.

Operational cost: this is a less sensitive variable than capital cost, but clearly must be managed.

Fuel: For woodchip, +/-£1.5/GJ represents a fluctuation of +/-£19/te or +/-30% around a base case of

£65/te. This variation has a significant impact on the outturn Bio-SNG cost. An increase of this level

would provide a Bio-SNG cost significantly beyond the gas prices considered . For SRF +/-£1.5/GJ

represents a more significant fluctuation of +/-£27/te or +/-100% around a base case gatefee of -£27/te.

Whilst this is a sensitive variable, the bio-SNG cost could be viable even in the stress case.

RHI: The RHI is a very sensitive variable. Increasing this to £50/MWh would enable projects based on

both feedstock types to attain a competitive outturn Bio-SNG cost on the assumption set indicated, and

should provide sufficient project returns to attract investment for an SRF or SRF-Biomass blend facility.


57

Impact of heat sales. The sale of heat can provide a cost reduction for the Bio-SNG. Depending on the

level of RHI assumed for the heat offtake) £16-25/MWth), the biogenic content of the feedstock and the

displaced heat cost (assumed here to be £20/MWh), for the large scale facility, the impact on the

levelised cost of heat sales range between £0.16-0.23/MWth of Bio-SNG for each MWth of heat

delivered. The recoverable heat potentially available from the large scale facility could be significant,

depending on the grade of heat required, but in the case of low grade could be over 50MWth, so the

limiting factor is more likely to be the offtake requirement. For an offtake of 10MWth, this indicates the

bio-SNG cost could be reduced by ~£2/MWth.

6.3.3 Comparison with an SRF fuelled electricity project By way of comparison, an analysis has been drawn up for a small, 50MWth project configured to produce

electricity via gas engines, with an SRF feedstock.

For this case, the estimated net output is 13MWe corresponding to a net conversion efficiency of 26%.

The capital cost can be reduced as there is no requirement for the water gas shift, the gas processing

does not need to be undertaken to the same level of contaminant removal and there is a small saving for

generators compared with the assumed cost for methanation. The total capital cost is assumed to be

£70Million. The same operational costs are assumed. The availability is assumed to be somewhat higher

at 7600hrs. The build time is assumed to be 24months due to the simpler gas processing and packaged

generators which allow for offsite production line manufacture, compressing the build out time.

Using DECCs 2010 figures for wholesale electricity, consistent with the wholesale gas price of 59p/therm

assumed for the Bio-SNG analysis, (£60/MWh) and 2 ROCS (£50/ROC) and 60% biogenic fraction, the

pre-tax project return, assuming no leverage is 10% (real). Without carrying the additional costs

associated with pressurised, oxygen blown gasification (not required for reciprocating engine power

generation only) this return could be further increased. By comparison the Bio-SNG project gives a

project return of <5% at 59p/therm.

This demonstrates that commercially, a small syngas project is better configured to produce electricity

under the current RO regime, than producing bio-SNG under the proposed RHI at £40/MWh. It also

suggests that an appropriate development pathway for Bio-SNG demonstration could be a project

predicated on power generation with a slip stream for Bio-SNG production.

At the larger scale,using a Gas turbine at higher efficiencies, the capital cost is assumed to be £270M the

pre-tax unleveraged project returns for an electricity plant are likely to be in excess of 20%, even taking

more conservative, investment case, figures for ROCs and wholesale power. This shows that without an

increase in the RHI over and above the £40/MWh proposed, that electricity would remain a strongly

preferred investment case. An increase in RHI to £50/MWh would narrow the gap, although electricity is


58

probably still marginally preferable. However this would require a further level of analysis and costing

based around a specific project to confirm where the relative advantage lay in this case. It must also be

noted that there is more international activity based on gasification for power generation, the regulatory

regime and practice for connection is more established, and the RO support mechanism has a longer

track record with investors.

0

20

40

60

80

100

120

140

160

180

200

Bio‐SNG (p/therm) Electricity (£/MWh)

Net cost of Bio‐SNG (p/therm) & Electricity (£/MWh)

LCof Bio‐SNG (RHI at £40/MWh) & electricity with 2 ROCs ( £50/MWh

Small Large

TypicalNatural Gas prices range (p/therm) and electricty price (£/MWh)

Figure 6.9 Levelised cost of Bio-SNG supported by the RHI at £40/MWh and renewable electricity supported by 2 ROCS as Advanced Gasification based on SRF with 60% biogenic content

6.4 FINANCIAL CONCLUSIONS From this analysis, the following conclusions can be drawn

A support mechanism such as the RHI is critical for Bio-SNG – without it, conversion of biomass

into Bio-SNG for the purpose of Grid injection will not happen at any scale using any fuel.

With the current assumed support level under the RHI of £40/MWh, a Bio-SNG Project at

50MWth will not be viable (on any of the fuels assessed). Either some form of capital grant or

subsidy enhancement is necessary for a small Bio-SNG Project to operate.

However at 300MWth the current support level is sufficient to enable competitively costed bio-

SNG project, particularly if fuelled fully or partially by a waste derived fuel. This indicates that

there could be a long term role for Bio-SNG commercially.


59

The issue is how to get from the current position to this scale of project in light of the technical

and commercial risks. This is particularly the case if the RHI does not transpire at the currently

proposed level.

Projects configured to generate electricity under the current banded RO regime are commercially

favourable at both scales, and particularly attractive at larger scale. A small project generating

electricity from SRF under the RO regime may offer a development route for Bio-SNG. By

leveraging the mature and favourable electricity support regime a syngas platform could be

established from which a Bio-SNG project could be developed.

In this case, the project may just be acceptable using waste fuels, although it is unlikely that a

private investor could countenance the risk for this level of reward without a longer term

perspective or desire to operate in the sector – and ultimately develop a facility at larger scale.

In all cases it is clear that the use of virgin material can only have a limited role, and that the use

of waste is vital to maintain the projects commercial integrity. This financial analysis presumes

that the technical issues relating to Bio-SNG production, particularly from waste, can be

overcome. The international Bio-SNG projects currently being developed are predicated on

biomass. However, there are a number of international waste-to-syngas projects under

development for both GT/ICE power applications as well as bioliquids. If these succeed, then the

transition to Bio-SNG production presents no obviously insurmountable technical hurdles.

The use of waste wood may provide a shorter term development route; the enhanced level of

support due the high biogenic fraction offsets the reduced cost of the fuel, and may be slightly

less technically challenging. However, in a market increasingly seeking low cost biomass

feedstock, waste wood is likely to become increasingly valued, particularly for larger projects, and

less material is likely to be available.

The quantum of investment is significant – even for the development project. In the current

financing climate this presents a challenge.


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7 Lifecycle carbon emissions and Cost of Carbon Analyses compared with alternatives

Bio-SNG offers two primary benefits: (a) It is a route to provide a substitute for natural gas - that is it has

a contribution to play in security of supply, and (b) it offers reduced carbon emissions by virtue of the fuel

being biogenic, and therefore considered renewable.

In analysing the latter, it is important to consider (a) the actual environmental footprint taking a whole

lifecycle analysis of the different pathways of production (primarily different fuel types) as compared with

alternative decarbonisation options, and (b) the cost per tonne of carbon abated by this route compared

with other decarbonisation options.

The cases considered as baseline cases and counterfactuals are:

Domestic and commercial heating with counterfactuals of oil, gas, electrical (including

renewable), direct biomass use and GSHP

Transport applications with counterfactuals of petrol/diesel/conventional CNG/electrical vehicles.

7.1 LIFECYCLE CARBON EMISSIONS

Analysing the full lifecycle carbon emissions49 of a process is complex, requiring not only detailed

understanding of fuel types, process configurations, the emissions profile of the counterfactual cases, and

the methodology for such analysis, noting particularly the role of co-products and how they are valued.

Recently North Energy undertook an analysis for the National Non-Food Crop Centre for Bio-SNG

produced from a variety of different routes50. The key observations from this analysis are summarised

below.

North Energy undertook the analysis using two methodologies: (a) based on the UK EA methodology

using the UK BEAT tool developed in 2008, and (b) based on the requirements of the Renewable Energy

Directive. The key difference between these two methodologies is how ‘substitutions’ and ‘credits’ are

treated. Inter alia, this encompasses how the carbon savings/penalties of co-products are valued, and

how displaced product pathways are handled – for example what the presumed destination of a waste

product would have been, had it not been used for this application, and what the carbon profile of that

displaced route is considered to have been. It should be noted that ultimately the UK will need to

demonstrate savings based on the final agreed EU methodology for compliance with its Renewable

Energy Directive Targets. 49 Here the unit is correctly termed the Carbon dioxide equivalent (CO2e) emissions, as this also includes the greenhouse gas impacts of other gases such as Methane and Nitrous oxides 50 “Analysis of the Greenhouse Gas Emissions for Thermochemical BioSNG Production and Use in the United Kingdom” Project Code NNFCC 10‐009 Study funded by DECC and managed by NNFCC North Energy Associates (June 2010)


61

A B

C D


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Figure 7.1 (Overleaf) Percentage Net Greenhouse Gas Emissions for Bio-SNG fired heating relative to fossil fuel alternatives for (a) BEAT2 methodology and (b) EC RED methodology and, Percentage Net Greenhouse Gas Emissions for Bio-SNG transport fuel relative to fossil fuel alternatives for (c) BEAT2 methodology and (d) EC RED methodology (North Energy Associates, June 2010)

The data shown illustrates that whilst the actual methodology does have an impact, the following broad

conclusions can be drawn:

The carbon savings in both the heating and transport sectors are similar

Bio-SNG from virgin biomass typically saves in excess of 90% by either methodology

In general production from pellets offers slightly lower savings due to energy used in the pellet

manufacture

In general imported feedstock offers slightly lower savings

In general wastes offer better savings due to the “credits” system (and this is where the difference

between the two methodologies is most stark)

The analysis of RDF (Refuse Derived Fuel) requires a further commentary. The RDF used in this analysis

is a high biomass RDF manufactured from mixed waste. The baseline RDF production route used in the

analysis is an autoclave system which uses significant quantities of process heat, which erodes the

greenhouse gas savings. A more typical RDF would be processed using Mechanical Biological

Treatment which would have a much lower specific energy consumption and would have a greenhouse

gas saving profile similar to that of cardboard RDF for the biogenic fraction. However in this case, the

biogenic fraction would only be 60% of the biogas, and therefore the greenhouse gas savings would be

~60% of that of cardboard RDF – which would therefore offer greenhouse gas savings similar to the RDF

case shown, but for a different reason. This distinction is critical because the incentive structure would

only apply to the biogenic fraction, and the greenhouse gas saving per unit of incentive support remains

very high.

It is instructive to note that the detailed analysis here could be approximated by considering the savings

to be at least the full tailpipe emissions associated with individual fossil fuel pathways (ie without needing

to consider the full lifecycle analysis)51

In all cases it is assumed that whilst the lifecycle analysis accounts for the emissions associated with

distribution, it is presumed that the existing infrastructure has sufficient capacity (gas and electricity) .

51 For example, here the lifecycle emissions of a gas boiler is 245kg/MWh and the emissions for Bio‐SNG using imported forestry residue is 30kg/MWh is a saving of 215kg/MWh. The tailpipe emission of natural gas is 185kg/MWh, so this emissions figure gives an approximate, but conservative savings estimate.


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The key specific emissions, based on the North Energy lifecycle analysis are shown in Figures 8.2 and

8.3 for heating and transport applications respectively, demonstrating the substantial emissions savings

from biogenic fraction of the Bio-SNG. The relative saving for SRF will be reduced according to the

biogenic fraction.

0

20

40

60

80

100

120

140

160

180

200

Diesel Gasoline Bio‐SNG

CO2e

emission

s g/km

Lifecycle emissions of Bio‐SNG as a transport fuel compared with Diesel & Gasoline, per kilometre

Figure 7.2 CO2e emissions per kilometre in the transport sector compared with fossil fuel alternatives (EU RED methodology)

0

50

100

150

200

250

300

350

Oil boiler Gas boiler Bio‐SNG using UK forest residues

Direct heating using UK forest residues

CO2e

emission

s kg/M

Wh

Specific emissions for heating for fossil fuels, Bio‐SNG and direct biomass heating

Figure 7.3 CO2e emissions in the heating sector compared with fossil fuel alternatives (EU RED methodology)


64

A further important comparison was also made by North Energy – comparing the greenhouse gas savings

for the direct use of biomass for heating with that via SNG. Using the RED methodology for forestry

residue woodchip feedstock, the specific emissions for direct heating is 13kgCO2e/MWhth and the

emissions for Bio-SNG is 15kgCO2e/MWhth, compared with emissions from oil and gas heating at 313

and 245 kgCO2e/MWhth respectively. Therefore the savings in both cases are approximately 95%

compared with fossil fuel, and importantly the saving using Bio-SNG is essentially the same as using

direct heating, but with elimination of any demand-side modifications for the heat users via the SNG

route.

The annual CO2e savings for three of the larger facilities operating on biomass is 1Mte of CO2e per

annum if used to displace natural gas heating, and slightly higher if it displaces conventional transport

fuel. If Biogas were to displace a third of the domestic natural gas consumption and bio-SNG

represented two thirds of that, then the CO2e savings would be ~15Mte pa when fuelled by biomass.

7.2 COST OF CARBON ABATEMENT VIA BIO-SNG

As discussed above, the use of Bio-SNG from biomass gives a typical CO2e saving equivalent to at least

that of the tailpipe emission of fossil fuel it displaces, for heating and transport. Furthermore, a bio-SNG

vector provides approximately the same saving as that achieved by direct use of biomass for heating.

Strategically the UK needs to consider the most cost effective approach for decarbonising. An analysis

has been undertaken which considers the cost of decarbonising, based on the current and proposed

levels of renewable support subsidy52 considered to be adequate to achieve market penetration of the

particular technology.

In this analysis, it is assumed that the existing RO regime, the proposed RHI regime and the existing

transport fuel differentials are sufficient to bring about market penetration of the technologies supported,

that is to say, these incentives represent the necessary additional cost of delivered utility (heat, electricity

and motive power) to a consumer compared with the conventional fossil fuel alternatives. It is also

assumed that at present the cost of carbon under the EU ETS where it applies has simply been absorbed

into the baseline cost of electricity across the board, and due to free allowances does not at present

relate to the cost of avoiding carbon emissions. Furthermore it is assumed that the existing infrastructure

(both gas and electricity) have sufficient capacity and so no further investment is necessary specifically

due to the expansion of the carbon abatement pathway.

52 In deriving the cost of the emissions savings, the Government’s Impact Assessments calculation is made on the basis of dividing the NPV of the incentive by the total tonnes of CO2 abated [noting that the cost is discounted over time, but the carbon abated is not]. The analysis here is viewed from the point of view of the direct cost to the consumer, ie the subsidy cost divided by the tonnes of CO2 saved, and where possible uses the full lifecycle emissions of CO2e.


65

For the transport comparison, the vehicles assumed are the Passat Ecofuel running on Bio-SNG, the

same vehicle in the 1.4l gasoline version, and the Nissan Leaf as an electric vehicle. In each case, the

vehicle is assumed to travel 20,000km pa using the appropriate fuel efficiency, and accounts for the

appropriate Road tax, fuel duty including rebates, the additional incentive cost to provide the renewable

gas and electricity (Offshore wind) and in the case of electric vehicles the grant support (£5000).

Separately the cost of carbon abatement for a range of electrical vectors is shown by way of comparison.

0

100

200

300

400

500

600

700

GSHP Grid electricity

GSHP renewable electricity at

2ROC

Domestic heating via

direct biomass

GSHP renewable electricity at

1ROC

Small commercial via direct biomass

Bio‐SNG Large commercial via direct biomass

Cost of carbo

n abated

(£/te CO

2e)

Cost of Carbon abated for heating applications

>£5000

Figure 7.4 Cost of carbon abated for heating applications


66

0

200

400

600

800

1000

1200

Electric car Grid Electric car renewables 2ROC Bio‐SNG

Cost of A

batemen

t £/te CO2e

Cost of Abatement

Figure 7.5 Cost of carbon abated for transport applications

For heating applications using gas as a counterfactual, Bio-SNG offers a cost per tonne of CO2e abated

of ~£175/te. This compares very favourably with direct biomass combustion for domestic applications

(£395/te), for small commercial applications (£285/te) but is somewhat more expensive than direct

biomass combustion for large scale commercial applications at ~£110/te. When using oil heating as the

counterfactual, the cost per tonne of CO2 saved reduces significantly to £135/te for Bio-SNG compared

with £305, £220 and £85 for the three cases discussed above. However it must be noted that the

appropriate counterfactual for Bio-SNG is natural gas, as the product can only be used where there is a

gas grid and where oil use is unlikely.

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 unit53, and over

£850 when compared with oil. When using renewable electricity (2 ROC supported offshore wind) the

cost 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. This is likely to be the case since heat demand is seasonal, such that

the peak demand for heat can be three times the energy required for electricity and transport combined.

53 “Getting warmer: a field trial of heat pumps” EST Sept 2010. This indicates a typical “System Efficiency” from its field trials of 2.4 (ie accounting for COP and system electrical loads). Whilst improved system efficiencies of eg 3.0 would reduce the cost per tonne of carbon abated, it is still significantly higher than for Bio‐SNG.


67

Therefore significant supply of heat via electricity would demand “significant additional generation plant

and network capacity operating at low load factors” 54.

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 electricity

- £600/ te CO2e). However, this analysis does suggest that whilst Bio-SNG offers significant carbon

savings for the transport sector, on a cost per tonne abated of £400/ te CO2e, the heating sector is a

preferable end market.

£0

£50

£100

£150

£200

£250

£300

£350

£400

£450

£500

£550

£600

FIT: PV (0.1‐5MWe)

FIT: Wind (0.1‐0.5MW)

FIT: Hydro (0.1‐2MWe)

Offshire wind

Anaerobic Digestion

Bio‐SNG Biomass combustion

Onshore wind

Co‐firing

Cost of carbo

n abated

(£/ te

CO2e

)

Cost of Carbon abated compared with Renewable electricity generated by various technologies

Figure 7.6 Cost of carbon abated for Bio-SNG compared with renewable electricity generated from various sources 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

54National Grid: “Gas as an essential fuel in supporting the transition to a low carbon economy A discussion paper by National Grid to support Ofgem’s RPI‐X@20 project.”


68

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 national driver 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.


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8 Risk Assessment and Financing Considerations

In accordance with good practice the development of any complex process facility should be

accompanied by an appropriate risk management strategy. The main classes of risk to be managed will

include:

Cost and schedule over-run

Functional integrity

Health and Safety

Feedstock supply, price and quality

Off-take security and security of revenues

Financing risks

Regulatory risks

A well conceived project execution plan for a Bio-SNG development can take account of these risk areas

through a range of contractual and technical provisions, however, where novel process configurations are

developed, and with a dependency on the nascent biomass fuel supply market, then additional risk

factors will be introduced. (It is assumed that from the existence of established infrastructure etc., there is

negligible risk of getting Bio-SNG to market – the market exists.) In addition it must be recognised that

that the market for renewable energy of all kinds is an artificial market, augmented by a variety of

government incentive schemes throughout the developed world, which being the products of political

intervention are liable to change with changing political priorities. Thus a Bio-SNG development strategy

needs to be clear from the outset how it would manage the following issues:

Political risk

Technology risk

Fuel supply risk

Resulting additional financing risks

Should there be any fundamental impediment posed by any of these issues then work on other aspects of

a development would be in vain.

Political risk is both domestic and international. Internationally the demand for and value of biomass

feedstocks is affected directly by the uncoordinated subsidies directed at the renewables industry by

national governments55. Biomass fuel suppliers will naturally sell to the market offering the best price if

new and more valuable markets emerge. Where the viability of a full scale Bio-SNG facility depends

upon imported biomass it is clear that a fuel procurement strategy would need to be developed to secure

supply price and volume for a number of years. Similar concerns extend to domestically produced fuels,

55 In 2008 / 9 the uncoordinated support schemes for renewable transport fuels in the UK and the USA, together with

some loose legal definitions had the effect of decimating the UK’s indigenous transport biofuels industry.


70

whether clean biomass or waste-derived materials since government support mechanisms across the

renewables sector, and with respect to carbon abatement generally continue to be incoherently variable

in some respects.

It is anticipated that the Renewable Heat Incentive may have the potential to provide the essential

increase in sales revenue that could make Bio-SNG production viable, however, it will be necessary to

verify that the uplifted revenues would be sustained for a sufficient number of years to assure an

acceptable project return; that is to say that the uplift would be “Grandfathered” from the date of

accreditation by Ofgem. It should be noted, however, that development expenditure prior to the date of

accreditation could be at risk of a change to the rules within the RHI. Given the substantial development

costs that a Bio-SNG development would entail, the developer should seek to minimise its per-

accreditation risk exposure.

The technical approach proposed in this report envisages the use of conventional and proven process

operations, however, their integration into a Bio-SNG facility is, save for a small number of plants

currently under development56 without any precedent or reference facility. Notwithstanding the maturity of

the process technologies that may be assembled into a Bio-SNG facility the whole plant would

undoubtedly be seen to be novel and unproven by suppliers of debt into project finance arrangements.

An objective assessment of technical risk will at the outset of a project design identify a degree of

technical uncertainty regarding integration of the various process operations comprising the complete

facility, however it is within the competence of a proficient process engineering industry to analyse and

resolve these issues to a level of certainty sufficient for an investment decision (however this costs effort

and money at the design stage). The question remains, however, as to whether the financial community

would be prepared to engage in detailed technical audit and verification of a proposed development or

whether they merely demand to witness a reference plant that provides a QED for the process concept.

Experience suggests that potential funding institutions would favour the latter, hence securing of project

finance for either a demonstration plant or a full scale facility is unlikely.

The perceptions of risk, and strategies for mitigation of risk have changed markedly over the last three

decades, driven largely by the development of philosophies in privatisation of utilities, corporate finance

and project finance. Prior to this, risk management in industrial developments was less formal and would

(wittingly or unwittingly) leave governments, company balance sheets and shareholders as the bank of

last resort. Modern norms57 for project finance seek to devolve as many risks as possible via commercial

arrangements to contracting counterparties – e.g. equipment suppliers, contractors, and banks – whilst

demanding unequivocal delivery of performance guarantees. These trends undoubtedly facilitate the

efficient use of capital, and reduce the number of unanticipated cost over-runs but with the corollary that

under such circumstances it is more difficult, or even impossible to arrange project finance for first-of-a-

kind energy projects. Thus contemporary norms for project finance sit uncomfortably with the emerging 56 Gussing and Gobigas – see Appendix 1 57 i.e. the gearing of equity with non‐recourse debt in order to give the lowest possible cost of capital.


71

demand to deploy new energy infrastructure that incorporates novel and unproven technologies or even

novel process configurations. Equally, corporate balance sheets tend to be insufficiently strong to

undertake large capital projects on balance sheet; the recent history of infrastructure developments being

undertaken with a combination of debt and corporate equity. In the post 2006/8 risk-averse banking

climate it is even more the case that conventional financing arrangements could only be used to deliver

infrastructure energy projects that use tried and tested (i.e. “proven”) technologies and designs. The

challenge therefore is to conceive project financing strategies that can accommodate first-of-a-kind

energy infrastructure projects such as facilities for the production of Bio-SNG.

It is commonly presumed by government and other stakeholders that given an adequate stimulus or

incentive “the market” will move to provide the technical innovation and development necessary to meet

the opportunity. For example, the banding in the Renewables Obligation is intended to doubly incentivise

the deployment of waste and biomass gasification facilities; to date there is little to show in terms of such

new technology plants being built and commissioned. This is equally the case for marine renewables and

to a lesser extent for offshore wind developments58. As a strategy for bringing new biomass energy

infrastructure into commission the banding of the RO is clearly not having the intended effect, however,

an appreciation of human decision making in a climate of risk shows why this should not be a surprise.59

In short, decision making within the energy industries is dominated by a reluctance to accept the

downside risks associated with technical novelty, feedstock insecurity and political vacillation; irrespective

of the magnitude of the projected returns. Moreover, economic analysis of most renewables projects,

including Bio-SNG shows that the enhanced income derived from support for renewables is required to

bring project income up to a level of marginal viability, with no premium for any unusual project risk.

Another popular misconception is that “demonstration” of a new technology would provide the essential

proof of concept to liberate funding from aspiring investment institutions. This has spawned a number of

government initiatives to promote the building of “demonstration facilities”60 on the presumption that

demonstration would be a sufficient condition to satisfy funding institutions in their requirement to invest

only in proven technologies. There are flaws with this line of reasoning. Firstly, demonstration projects

are likely (for reasons of cost and risk) to be a fraction of the required scale of facility that would be

deployed in a commercial plant; hence scale-up risks are still a material consideration. Secondly, the

period during which a demonstration plant is operated can in no way give an assurance of satisfactory

performance throughout an investment horizon for which project returns have been projected, for

example, a minimum of fifteen years.

58 Meeting the 2020 Renewable Energy Targets: Filling the Offshore Wind Financing Gap – PWC July 2010. Clearly it is now recognised by at least one of the major management consultants that pure financial incentives are in themselves insufficient to ensure deployment of new energy infrastructure, and that innovative financing mechanisms are required. 59 See The Utility Function of Risk, John von Neumann et al. 60 e.g. Defra’s New Technology Demonstrator programme, the Carbon Capture and Storage competition.


72

It is true that venture capital funds do invest in emerging technologies, but this is invariably at a much

smaller scale than would be required for a Bio-SNG plant and with the expectation of high returns and an

early exit for investors, coupled with the prospect of a global roll-out to a mass market; conditions that are

unlikely to be realised in energy infrastructure projects where a modest number of units would be

constructed and without any prospect of above-market returns. It is not surprising therefore that venture

capital funds have not yet sponsored a break-through in biomass energy generation technologies.

The result of even a successful venture capital funding or technology demonstration is the well known

investment “valley of death”, reflecting a state of technology development that is insufficient to attract

investment of further and necessary resources and in which under-resourced technology developers have

difficulty in fighting their way out of the corner in which they find themselves. It follows that in the absence

of any alternative financing strategy the first-of-a-kind risks must be taken by the project owner or investor

by means of a 100% equity position. A small scale, 50MWth Bio-SNG demonstration plant would cost in

the region of £70m, (and a full scale 500MWth facility in the region of £250m). In a commercial

landscape where this could not be part funded via debt this leaves the owner/shareholder or developer

staking a large amount of capital on a single, sub-commercial demonstration project in the possibly

unrealistic hope that at some point in the future it would provide sufficient demonstration to attract project

finance. Unless it can be clearly identified at the outset that a demonstration plant offers a route to

securing project finance then it may be necessary to see what it takes to go straight to a full scale facility.

Few organisations have the balance sheet strength to contemplate this, and those that do would be faced

with the same internal investment committee justifications as would be posed by an external debt

provider. In short, the technology investment case would need to be compelling in order to secure a

positive decision by a corporation to invest.

Fuel supply risks are undoubtedly influenced by changes globally to the various support mechanisms of

national governments and by the ongoing evolution of world energy markets. Increasingly they are

influenced also by considerations of sustainability, with ever increasing requirements for users to

demonstrate that their biomass fuel supplies are responsibly sourced. Some identified and existing

sources of biomass fuels will run the risk of being unsustainable in the future as this criterion is applied

more rigorously both to the existing inventory of biomass (mature woodland), or to farmed energy crops.

To manage fuel supply risks some major biomass power developers such as RWE are moving upstream

into the supply chain to secure producing assets, to gain a controlling position in the trading of biomass

fuels in this emerging market and to increase the diversity of sources globally. It may not be necessary to

compete with the likes of RWE; rather it may be preferable to enter into long term fuel supply contracts

with such powerful counter parties that are seeking to be market leaders in this area. Regarding the use

of waste-derived fuels it will be necessary to secure long term supply contracts with waste processors.

From the foregoing it may be concluded that the confirmation of the RHI at an adequate level of support

together with grandfathered rights may constitute necessary but insufficient conditions by which to justify

investment in Bio-SNG production. Some provisions would need to be made to tackle feedstock security,


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as well as technology and construction risks. Feedstock security is a question that a Bio-SNG developer

can manage itself through development of its upstream business, by contracting with majors like RWE

that are active in this field, by futures trading etc., however, the management of technology and

contracting risks may be beyond the powers of the Bio-SNG developer to handle alone.

In its report “Meeting the 2020 Renewable Energy Targets: Filling the Offshore Wind Financing Gap”

PWC identifies investment barriers that impede the timely deployment of facilities required to meet the

UK’s renewable energy targets. The problem identified in this report is not peculiar to offshore wind but

common across the sustainable energy sector; how to get substantial institutional investment into new

low-carbon energy infrastructure. PWC sets out a number of possible scenarios in its report, but key

among them is the notion that a publicly administered infrastructure development fund should be created,

perhaps from a consumer levy, that could be used in qualifying projects for project funding through the

critical engineering, construction and commissioning phases. Refinancing of projects when they reach

stable operation would recycle money back to the fund for use on subsequent projects. However, the

intent is to create a body of operational experience, by means of this “pump priming” exercise that will

provide the necessary confidence for institutional investors to invest in future projects of the same type.

PWC suggests that the quid pro quo for a developer benefiting from this kind of funding assistance could

be a reduction in the level of ROC support post commissioning. To the extent that ROC support is likely

to form an essential part of a project’s economic viability, Progressive Energy would argue that this would

constitute another barrier to renewables project developments. Nevertheless the PWC report sets out a

number of potential scenarios for overcoming the difficulties in financing new energy infrastructure: it can

be downloaded via the link referenced in Appendix 3.

To the extent that Bio-SNG (along with other significant sustainable energy sources) has the potential to

make an efficient contribution to renewable energy targets, it could be argued that the UK government

should be encouraged to understand that whilst the Renewables Obligation and the RHI are necessary

instruments, they are unlikely to be sufficient for the timely realisation of facilities on the ground, and that

some further measures - such as those proposed by PWC - need to be taken to manage technology and

construction risks on large capital projects.


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8.1 CONCLUSIONS FROM RISK ASSESSMENT AND FINANCING CONSIDERATIONS

Use of existing technologies will reduce technical risks but still leave a project finance hurdle.

Fuel supply risks need to be addressed from the outset.

A demonstration facility may not clear the way to project finance for a full scale project.

The developer should have a clear perception of incentives and the political / regulatory

landscape.

There are fundamental barriers to the timely funding of novel energy infrastructure.

Further financial provisions may need to be made to cover technology and construction risks.

Significant expenditure should not be committed until a pathway through all these issues is

identified.


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9 Preliminary Scoping of a lead, beacon project

9.1 BEACON PROJECT CONFIGURATION OPTIONS

The philosophical approach taken in this report has been to identify a route to efficient Bio-SNG

production that does not require research and development but is based upon the integration of

conventional and proven process operations that have been demonstrated elsewhere. Nevertheless it

remains to be established whether an investment case could be advanced that would offer sufficient

confidence to invest directly in a full scale 300Mwth Bio-SNG facility, or whether some sort of

intermediate development would be required to improve confidence levels to the point where the

investment case for a large scale plant could be accepted. This consideration is counterbalanced by the

realisation that the economies of scale given by a full scale plant are needed for a commercially viable

operation. Three potential basic development cases present themselves:

Small Scale Bio-SNG synthesis taking a slipstream of bio-syngas from elsewhere A small scale Bio-SNG synthesis operation taking a slipstream of bio-syngas over the fence from an

existing biomass or SRF gasification developer. There are some potential biomass / SRF gasification

projects slated for development in Teesside, and it may be possible to piggy back a small Bio-SNG

demonstration project onto one of these, given an amenable attitude from the core project developer.

Figure 9.1 shows the basic concept for this arrangement.

Figure 9.1 Small scale Bio-SNG synthesis using syngas from another project This process set-up would allow proof of concept for Bio-Syngas methanation, which may be seen as

valuable, however, one could make the observation that the methanation of synthesis gas (whatever its

origin) is a banal exercise and not really worthy of demonstration. Nevertheless, it should be noted that

catalyst manufacturers such a Johnson Matthey are undertaking developments of catalysts specifically for

syngas derived from biomass on the basis firstly that it may be possible to relax gas cleaning criteria if

tolerant catalysts could be identified and secondly that there could be as yet unknown traces of particular

contaminants in bio-syngas that need to be addressed. Equally it could provide a test site for the

demonstration of a compact micro-channel reactor supplied potentially by a company such as Oxford

Catalysts. This could represent an interesting development pathway since having achieved

Gasification Syngas scrubbing

Power generation

Methanation etc.

5%

Core project

Slipstream

Syngas conditioning

SNG comp. & export


76

demonstration at this scale, the up-scaling of the micro channel reactor concept entails minimal technical

risk since it would entail replication of the standard process module proven in the demonstration plant.

This development concept is a low risk, low cost step in the direction of meaningful volume production of

Bio-SNG, with the potential to make substantial progress via demonstration of a micro channel reactor.

However, it does rely on a third party producer of syngas, and the inherent technical and commercial risks

of the core project.

The development of a scalable demonstration facility at a size of around 50MWth

Conventional concepts of development pathways envisage “demonstration” of a technology as an

essential step towards securing project finance for a full scale facility. This report suggests in Section 7

that there could be flaws in this idea concerning whether the level of demonstration would be sufficient for

the purposes of securing project finance for a full scale facility. Before embarking on the development of

a demonstration project therefore it is essential to understand whether the resulting demonstration will

serve the intended purpose in this respect. This report also finds that there is little prospect of even a

relatively large Bio-SNG demonstration plant (50MWth) achieving commercial viability, in view of the

significant capital cost estimate of £70M. The economic analysis that supports this report reveals that for

viability such a plant would require a capital grant of approximately £45m or a hike in RHI contribution of

£40/MWhth. There is a hybrid development, however that might hold some promise of viability. In

principle it would be viable to develop a 50MWth waste fired power plant for the production of electricity,

benefiting as it would from the double ROC banding for gasification. Along the lines set out in Figure 9.1.

it would be possible to fit a slipstream in due course for the evaluation and development of a syngas to

methane process train, possibly incorporating the micro channel reactors for both WGS and methanation

reactions. However this would demand that the primary gasification train produces syngas suitable for

methanation (for example oxygen blown), such that the primary electrical plant does not generate

sufficient value to support the project. Nevertheless the challenge remains how to step up from such a

development to an investment in a full scale commercial Bio-SNG facility.

Development of a “Full-sale” 300MWth Bio-SNG facility. In consideration of a full scale plant development it is necessary to consider whether it could be

developed directly or whether some intermediate development step would be required to improve investor

confidence. In terms of the probability of technical failure, a full scale 300MWth facility is no more likely to

run into technical difficulties than a 50MWth demonstration plant; it is the magnitude of the relative

downside costs that is the issue rather than probability of failure. This raises the question as to whether

the downside associated with a £70M demonstration plant could be mitigated or controlled; if not then it is

difficult to see how such a demonstration plant could be developed at all. On the other hand if the

downside risks could be controlled to an adequate level then possibly the same proposition holds true for


77

a full scale plant development, especially given the use of conventional process technologies. Either

way, these are unlikely to be projects that could be funded with project finance (equity plus debt), and the

developer would need to be able to justify the risk / reward balance as the equity holder in the project.

Again, a hybrid development approach could offer risk mitigation potential, by taking syngas at full scale

from a conventional fossil fuelled source for the production of fossil SNG. Subsequently the source of

fossil syngas could move to co-firing biomass. Alternatively a biomass gasifier could be developed later

on for a dedicated supply of Bio-syngas to the SNG facility. In Teesside the Progressive Energy Eston

Grange development within the Teesside carbon dioxide capture cluster61 could be a possible source of

syngas for initial SNG production62. The general concept is outlined in Figure 9.2.

Figure 9.2 Hybrid development option A full scale Bio-SNG facility of 300MWth capacity would probably be built with two gasifier trains in order

to ”standardise” on gasifier frame sizes and to offer a degree of system redundancy. These would feed a

single gas processing train in order to benefit from the economies of scale. It will be readily appreciated

therefore that migration from fossil syngas to bio-syngas could be accomplished in stages as each of the

biomass gasifier trains is brought on line. This again assists in risk management in the gasifier

deployment, allowing also a staged ramp-up of biomass fuel supply.

9.2 LOCATION: THE NORTH EAST

The North is an attractive location for the development of the type of project contemplated here. It has a

long history of Chemical and processing industries. Therefore it has the necessary gas and services

infrastructure and the transport links as well as the people and skill base. The existing industrial backdrop

can accommodate the kind of processing plant under consideration, with a range of suitable and available

sites. Changes to and closure of existing industries mean that new facilities which offer employment and

regeneration are welcomed, so that a balanced view is taken during planning.

61 See Appendix 4 62 It must be noted that the increased complexity for the host project imposed by the Bio‐SNG addition may prove challenging.

Gasification Syngas scrubbing

CO2 capture

Methanation etc.

Syngas conditioning

SNG comp. & export

Power generation

Slipstream

Coal (+ Poss future biomass)

Future Biomass Gasifier plant

Storage / EOR


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The North East also has a track record of innovation. There are already three syngas based projects

slated or in development. The Ineos Bio facility will take solid waste and convert it to bioethanol via

gasification to syngas and subsequent biological conversion. Air Products have recently announced their

intention to build a 49MWe waste fuelled power generation facility using gasification to produce a syngas,

provisionally for conversion in a Gas Turbine. Progressive Energy are developing a coal fuelled syngas

facility incorporating carbon capture and storage. Each of these facilities will produce a synthesis gas

which could, in principle be partially converted to a Synthetic Natural Gas. In the event that the North East

is successful in bidding for government support for Carbon capture and storage, there may also be the

possibility of integrating Carbon Capture for the residual CO2 (fossil or biogenic) which is emitted in the

process.

9.3 SITE ANALYSIS

A high level screening exercise of sites in the Teesside area was carried out, focusing on those which

could accommodate a large scale facility, even if the build out was incremental. The primary attributes

considered were:

Transport infrastructure: Road/rail infrastructure for supply of indigenous fuel, and access to a

deep water port for economic import of fuel.

Gas connection with sufficient capacity (with a preference for lower offtake pressure than NTS,

providing sufficient capacity exists)

Electrical grid connection (to accommodate the supply/generation balance)

Commodities: water, cooling etc

The following attributes were considered desirable.

Access to Hydrocarbons to boost gas quality (LPG or high quality Natural Gas)

Existing Oxygen supplies

Syngas main to valorise intermediate and give flexibility

Potential to link into CCS networks for Carbon Dioxide disposal

Figure 9.3 shows the sites considered in the Teesside region. These sites have been selected for the

attributes and that they have been and could be available. However, in the Teesside region there are a

number of projects under development with site deals and options being negotiated confidentiality. This

can only be explored as the project becomes more mature, as can the other important commercial

considerations associated with a particular site. As can be seen, Teesside has a wide range of potential

sites. Table 9-1shows the evaluation of the sites.


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Site Ref Port Road Rail Gas NTS

Gas

LTS Elec Ser-

vices Cool-ing

Seaton Port A

Seal Sands B/C

Clarence Port D ? ?

Billingham Reach E/H

Norton Bottoms F ? ? ? ?

South Bank G Pos

Corus K - Priv

Sembcorp L Priv

Table 9-1 Evaluation of potential sites From this analysis, two sites were considered as most interesting; D and G, either side of the Tees,

primarily due to their proximity to port and transport infrastructure, as well as other facilities. These are

shown in Figure 9.4 As can be seen, neither area is currently constrained with regard to space, even for

a relatively large facility, although the exact footprint will depend critically on the level of fuel processing

required on the site, as well as logistic and storage arrangements. An investigation into the gas

Figure 9.3 Potential site sin the Teesside region


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infrastructure showed that both sites have reasonable accessibility to medium to high pressure gas mains

with sufficient capacity for 20,000Nm3/hr (Figure 9.5). Both these sites are believed to form part of

regional development plans, specifically designed to encourage and enable development. These sites are

also relatively close to the slated syngas development projects under way, with Air Products and Ineos

Bio on the North side of the Tees, and the Eston Grange Project on the South. Figure 9.6show the

photographs on the sites considered. The facilities shown in Appendix 1 would not be out of place in

Teesside. In summary, it is clear that Teesside offers a range of potentially suitable sites for a project of

this type.

Figure 9.4 North and South bank sites of most interest


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Figure 9.5 Gas Grid options


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Figure 9.6 Images of the North and South Bank sites


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9.4 REGIONAL FEEDSTOCK

In addition to ascertaining the availability of potential sites, it is also important to consider the availability

of feedstock. Teesside does have a significant number of biomass and waste projects operating or slated

as shown in Table 9-2. These represent over 2.5Mte of biomass and 1.4Mte of waste. Clearly such

projects demonstrate that Teesside does have both the transport infrastructure and access routes to both

types of resources. However, these resources are clearly sought after to support these projects. The

majority of this resource is for slated/in-development projects, not all of which will happen.

Existing/in-build te pa Slated te pa

Biomass Wilton 10 300,000 MGT Power 1,500,000

Lynemouth co-

firing potential

~200,000 BEI 400,000

Gaia Power 400,000

Waste SITA, Haverton 390,000 Ineos Bio 100,000

Haverton Ext 190,000

Wilton 11 400,000

Air Products 300,000

Table 9-2 Teesside: slated feedstock consumptions


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10 Conclusions Methane is an attractive heat and transport fuel vector. Bio-SNG is a production route which offers the

possibility of substantial scale renewable methane for injection into the grid and use in transport.

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.

Implementation of Bio-SNG will only take place with the appropriate tax, incentive and legislative

environment. Incentives must be structured such that such projects are commercially attractive compared

with competitive users of biogenic energy resources, and the regulatory environment must be clear and

appropriate.

Whilst there is substantial indigenous and international biomass resource in the form of ‘pure’ biomass

and waste derived fuels, 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.

Securing feedstock on contracts of sufficient term and appropriate price for financing presents a

challenge, and 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. From a technical perspective

biomass fuels are generally less well understood than fossil fuels, and the technologies that use biomass

fuels are less well developed, however, specification and quality control are vital determinants of project

success.

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. It is proposed in this work that established gasifier configurations

are adopted, such as direct fluidised beds, rather than emergent technologies. 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. Whilst these processing

elements are all conventional, 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

lead to unnecessary processing.

Two representative scales of facility at 50MWth and 300MWth input would produce approximately

230GWh and 1400GWh of Bio-SNG per annum. This represents sufficient gas for approximately 15-


85

100,000 households or 25,000-150,000 passenger vehicles. Three of the larger facilities would supply 1%

of the UK domestic gas market.

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 123-185p/therm at small scale and at large scale 24-96p/therm for SRF,

Woodchip and pellet feedstock respectively. With the proposed incentive regime, a large SRF fuelled

facility has the potential to provide gas effectively. 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. At the smaller scale, Bio-SNG cannot be supplied competitively from any fuel. A gasification

facility configured to generate electricity is likely to be commercially preferable to one configured to

produce Bio-SNG, unless the Renewable Heat Incentive is significantly higher than the £40/MWh

proposed

Full lifecycle analysis of Bio-SNG production shows that for many types of feedstock, the lifecycle CO2e

savings of Bio-SNG compared with fossil fuel alternatives are typically ~90%. This saving is similar for

both conventional heating and transport applications. This analysis also demonstrates that the savings for

the Bio-SNG production route are very similar to those achieved using direct biomass heating. Given that

the Bio-SNG solution has much lower demand-side constraints and therefore could achieve greater

market penetration, it is an attractive route.

Strategically the UK needs to consider the most cost effective approach for decarbonising. For heating

applications using natural gas as a counterfactual, Bio-SNG offers a cost per tonne of CO2e abated of

~£175/te. This compares very favourably with direct biomass combustion for domestic applications

(£395/te) and for small commercial applications (£285/te), as well as with Ground source heat pumps

(£5500/te). 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, however, this analysis does suggest that on a cost per tonne abated, the heating

sector is a preferable end market.

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, fuel supply

and financing risks that need to be addressed. 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 energy developments 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


86

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. In light of the financial analysis, a project at

300MWth fuelled by SRF could be 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, such as one

predicated on an existing or already proposed syngas platform.

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. High level site screening analysis

indicates that there are sites in the Teesside region suitable for either scale of facility with good transport

infrastructure, although there is potential pressure on feedstock resources in the region.


87

Appendix 1

Examples of Relevant Gasification Projects

Dakota

The largest SNG facility in the world, with 3GWth input capacity (producing ~200,000 Nm3/hr CH4),

fuelled by lignite. Started operation in 1984. Gasifiers: Lurgi Dry Ash with Rectisol gas cleaning. Has

Carbon capture fitted.

Gussing

Fuel: woodchip, 8MWth input to power. ~40,000 Gasifier and engine hours. Bio-SNG produced June

2009


88

Gobi Gas

Fuel: Wood pellets. Indirect gasifier. Phase 1: 32MWth input, Contracting 2010. Phase 2 (2015):

120MWth input, Technology undefined

High Temperature Winkler

Production of Methanol at various scales fuelled by lignite and MSW


89

Choren

50MWth facility fuelled by woodchip for the production of Biodiesel using Fischer Tropsch. Gasifier

operational, F-T in commissioning as of 2010.


90


91


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Appendix 2

Extract from the Smartest Energy Informer, 02 August 2010

Consultant calls for Government to plug offshore funding gap As the Government continues to push for aggressive growth in offshore wind investment, a recent

consultant report has highlighted the need for further public support.

In Meeting the 2020 Renewable Energy Targets: Filling the Offshore Wind Financing Gap published late

last month, PricewaterhouseCoopers’ (PwC) said a “quantum leap” in offshore wind capacity was

required to meet current government targets. But an “equal leap” was needed in support structures to

deliver investment.

The report proposed four solutions to supplement the current incentive framework:

• underwriting construction and technology risks by a consumer levy. This solution would share the risks

in construction among the developer and consumer for a limited time through a levy on electricity

usage, but this would be recouped through a lower Roc award level once the project was operational;

• a regulated asset regime. This solution would share the construction and commissioning risk between

the developer and an administrator. Any potential shortfall in selling to the market would be covered

through a consumer levy. Once the wind farm had demonstrated “operational stability”, it would be

auctioned off, and the winning bidder would be the one offering the lowest required return on the

capital on the regulated asset base;

• additional Rocs for a limited period. This solution would boost the short-term financial return for the

investor in the “first couple of years” of operation. Suppliers, and indirectly consumers, would bear the

costs through increased Roc payments; and

• bonds or an equity fund. This solution could increase the returns on investment rather than reducing

the risk. It would involve making investments in offshore wind projects tax free to the public through

an extension of the current ISA allowances. The taxpayer would bear the eventual cost in the form of

reduced income tax.

This report suggests current measures still fall short of what is needed to crystallise the necessary

investment.

For the full PWC report see:

http://www.pwc.co.uk/eng/publications/meeting_the_2020_renewable_energy_targets.html


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Appendix 3 – Extract from the Gas Safety (Management) Regulations

Schedule 3 Content and other characteristics of gas Regulation 8 Part I Requirements under normal conditions 1 The content and characteristics of the gas shall be in accordance with the values specified in the table below. Content or characteristic Value hydrogen sulphide content ≤5mg/m3; total sulphur content (including H2S) ≤50mg/m3; hydrogen content ≤0.1% (molar); oxygen content ≤0.2% (molar); impurities shall not contain solid or liquid material which may interfere with the integrity or operation of pipes or any gas appliance (within the meaning of regulation 2(1) of the 1994 Regulations) which a consumer could reasonably be expected to operate; hydrocarbon dewpoint and water shall be at such levels that they do not interfere dewpoint with the integrity or operation of pipes or any gas appliance (within the meaning of regulation 2(1) or the 1994 Regulations) which a consumer could reasonably be expected to operate; WN (i) ≤51.41 MJ/m3, and (ii) ≥47.20 MJ/m3; ICF ≤0.48 SI ≤0.60 2 The gas shall have been treated with a suitable stenching agent to ensure that it has a distinctive and characteristic odour which shall remain distinctive and characteristic when the gas is mixed with gas which has not been so treated, except that this paragraph shall not apply where the gas is at a pressure of above 7 barg. 3 The gas shall be at a suitable pressure to ensure the safe operation of any gas appliance (within the meaning of regulation 2(1) of the 1994 Regulations) which a consumer could reasonably be expected to operate. 4 (1) Expressions and abbreviations used in this Part shall have the meanings assigned to them in Part III of this Schedule. (2) ICF and SI shall be calculated in accordance with Part III of this Schedule. Part II Requirements for gas conveyed to prevent a supply emergency 1 The requirements of the gas referred to in regulation 8(2) and (4) are –

(a) WN – (i) ≤52.85 MJ/m3, and (ii) ≥46.50 MJ/m3; and

(b) ICF≤1.49, and in all other respects the gas shall conform to the requirements specified in Part I of this Schedule, as if those requirements were repeated herein. 2 (1) Expressions and abbreviations used in this Part shall have the meanings assigned to them in Part III of this Schedule. (2) ICF and SI shall be calculated in accordance with Part III of this Schedule. Part III Interpretation 1 In this Schedule – “bar” means bars (absolute); “barg” means bars (guage); “C” means degrees Celsius; “C3H8” means the percentage by volume of propane in the equivalent mixture; “equivalent mixture” means a mixture of methane, propane and nitrogen having the same characteristics as the gas being conveyed and calculated as follows – (i) the hydrocarbons in the gas being conveyed, other than methane and propane, are expressed as an equivalent amount of methane and propane which has the same ideal volume and the same average number of carbon atoms per molecule as the said hydrocarbons, and (ii) the equivalents derived from (i) above, together with an equivalent for all of the inert gases in the gas being conveyed, expressed as nitrogen, are normalised to 100%, such that the equivalent mixture of methane, propane and nitrogen has a Wobbe Number equal to that of the gas being conveyed;


94

“ICF” means the Incomplete Combustion Factor; “mg/m3” means milligrams per cubic metre at 15C and 1.01325 bar; “MJ/m3” means megajoules per cubic metre where the calorific value of a dry gas is determined on the basis that the water produced by combustion is assumed to be condensed; “N2” means the percentage by volume of nitrogen in the equivalent mixture; “PN” means the sum of the percentages by volume of propane and nitrogen in the equivalent mixture; “relative density” means the ratio of the mass of a volume of the gas when containing no water vapour to the mass (expressed in the same units) of the same volume of air containing no water vapour under the same conditions of temperature and pressure; “SI” means the Soot Index; “WN” means the Wobbe Number; trigonometric functions are to be evaluated in radians. 190 The Wobbe Number of gases should be determined on the basis that any water vapour in the gas has first been removed. 2 In this Schedule, ICF, SI and WN shall be calculated in accordance with the following formulae – ICF = WN-50.73+0.03PN 1.56 SI = 0.896 tan-1 (0.0255C3H8 - 0.0233N2 + 0.617) WN = calorific value “relative density” means the ratio of the mass of a volume of the gas when containing no water vapour to the mass (expressed in the same units) of the same volume of air containing no water vapour under the same conditions of temperature and pressure; “SI” means the Soot Index; “WN” means the Wobbe Number; trigonometric functions are to be evaluated in radians. 190 The Wobbe Number of gases should be determined on the basis that any water vapour in the gas has first been removed. 2 In this Schedule, ICF, SI and WN shall be calculated in accordance with the following formulae – ICF = WN-50.73+0.03PN 1.56 SI = 0.896 tan-1 (0.0255C3H8 - 0.0233N2 + 0.617) WN = calorific value relative density Guidance on determining whether gases fall within the criteria set out in Parts I and II of Schedule 3 191 The characteristics of a gas which can be accepted into the network under normal conditions (Part I of this Schedule), and those which may be authorised by the NEC (Part II of this Schedule) to prevent a supply emergency, have been derived from work carried out by Dutton et al (see references section at the end of this publication) on gas interchangeability. The work was carried out against a background of declining gas supplies from the southern North Sea and replacement supplies being provided from an increasing number of other sources. It was necessary to ensure that these new gas supplies were interchangeable with existing supplies, and that established standards of appliance performance and safety could be maintained without the need to adjust appliances. 192 Gases from diverse sources were burned on several types of gas appliance and their performance observed. From this parameters were established within which gases could be safely consumed. This led to the production of a 3-dimensional diagram together with equations for calculating the related indices for gases that contained significant quantities of hydrogen, and a simplified 2-dimensional version of the diagram for essentially hydrogen-free gases. As gases supplied to the UK are hydrogen-free, the 2-dimensional diagram, modified to suit existing conditions, has been used. The diagram has axes of Wobbe Number and equivalent mixture (propane plus nitrogen). 193 The following technique should be used to determine whether a particular gas composition complies with these Regulations:


95

(a) The Wobbe Number (real, gross) is calculated by methods outlined in International Standard ISO 6976: Natural gas. Calculation of calorific values, density, relative density and Wobbe index from composition 2nd Edition 1995, at standard conditions of 15C and 1.01325 bar.

(b) The equivalent composition of the gas (and hence the equivalent propane plus nitrogen) is calculated as follows:

(i) the non-methane/propane hydrocarbons are converted to methane and propane in accordance with Dutton, where:

n all isomeric forms of an alkane (eg, normal, iso and neo pentane) have the same equivalence; n alkenes and aromatic components have the same equivalence as the alkane of the same carbon number;

(ii) all the inert gases are expressed as an amount of nitrogen which when added to the amounts of methane and propane from (i) above, and normalised to 100%, gives a mixture having the same Wobbe Number (real, gross) as the original gas.

The normalised mixture in (ii) is also the equivalent gas having the equivalent amounts of propane plus nitrogen. (c) Acceptable gas mixtures are those where the intersection of Wobbe Number and equivalent mixture (propane plus nitrogen) lies within the envelope of gas conforming to Parts I or II of this Schedule depending on the circumstances.


96

Appendix 4 The North East CCS Cluster

The proposed North East CCS Cluster is in the heartland of the UK’s heavy process and chemical

industries. Design and pre-FEED engineering has been undertaken for all elements of the CCS chain and

key arrangements put in place to support a project plan which aims for first operation before the end of

2015.

Captured CO2 will be transported in a new pipeline for storage, and potential EOR, in an oil field in the

Central North Sea. The pipeline is routed to also allow storage in a saline aquifer with a CO2 storage

capacity in excess of 1bte providing risk management to the storage element and allowing storage in a

large saline aquifer to be demonstrated. The offshore pipeline has been sized to accommodate additional

CO2 from Teesside and the wider North East.

Development work has been undertaken on two substantial anchor CO2 capture sources either or both of

which could underpin the commercial development of the network, as well as provide demonstration of

pre-combustion capture at a scale of at least 400MWe. The facility at Teesside will be a new build syngas

plant which generates decarbonised hydrogen from coal for conversion to power in a CCGT (ie operating

as an IGCC) as well as for use by Industry in the area. At Lynemouth, configuring the existing coal power

station with pre-combustion capture provides demonstration of an IGCC retrofit with capture to an existing

coal power station. Each facility would capture in excess of 2.5million tonnes of CO2 per annum.

The region has numerous substantial emitters of carbon dioxide which will be able to link into the core

CO2 infrastructure, either via capture from their existing facilities, or by the use of decarbonised feedstock

and fuel. Specific existing industrial players are actively pursuing the decarbonisation options that CO2

infrastructure would offer. Furthermore the network will enable inward investment into the UK by other

high carbon emitters from around Europe for whom the unique storage opportunities afforded by the

North Sea enables decarbonisation of their industry.

Eston Grange IGCC, Teesside Offshore Infrastructure Lynemouth Power Plant


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The need and timescale for CCS in the UK

In the short term CCS is needed in the UK to enable coal generation to be maintained in the energy mix,

strengthening security of supply by avoiding over dependence on imported gas. New generating capacity

is required from 2015 onward and there is an incentive to either extend the life of existing coal stations by

fitting CCS or build new stations to begin operation on this timescale.

In the longer term it is expected that gas generation will also need to be decarbonised in order to reach

emission reduction targets in 2030 and beyond. However the higher specific CO2 emissions and more

urgent need associated with coal generation indicate that the policy of focussing on coal and supporting 4

coal fired CCS projects in the first instance is appropriate.

UK industry will become exposed to increased costs from the Emissions Trading Scheme from 2013.

Many industrial sources are smaller than those associated with power generation but nevertheless the

emissions cost can have a significant effect on profitability. There is concern in Teesside, which has one

of the highest concentrations of energy intensive and process industries in the UK, that the increased

costs may cause significant business contraction and job losses.

By themselves most industrial emitters are unable to support the full capital costs of transport and storage

as well as capture. The availability of CO2 transport and storage infrastructure is needed to support

decarbonisation of these industries, some of which of have very low capture costs but no means of

disposing of the captured CO2. For some industries other decarbonisation strategies may be appropriate

including, as is proposed at Teesside, using decarbonised feedstock from a dedicated plant producing

decarbonised syngas for industrial as well as power industry use.

Certainly for Teesside it is crucially important that, at the least, CO2 transport and storage infrastructure is

put in place as soon as possible to allow industries that become exposed to the ETS in 2013 to consider

investment in capture plant or use of decarbonised syngas to mitigate the risk to their business. The

marginal cost of sizing the spine pipeline from the first capture project to CO2 store to accommodate CO2

from additional geographically clustered, capture projects is low. Right sizing of the pipeline against

anticipated future need provides real benefits to UK plc by providing a framework for investment decisions

for industry and other power station owners to decarbonise their own operations.

The UK oil province is mature and annual production is falling rapidly. CO2 injection into mature oil fields

is an established technique for recovering otherwise unrecoverable oil. Durham University have estimated

that the use of CO2 to enhance oil recovery has the potential to recover >3b barrels of oil from the North

Sea if applied soon. The network which has been designed to transport CO2 from Teesside and the

wider North East takes CO2 to the central North Sea where it is available for commercial EOR use. The

spine pipeline has been sized to transport c15mteCO2/yr. If applied for EOR this could produce c1b

barrels of otherwise unrecoverable oil extending the life of existing oil fields for up to 20 years.


98

The status of CCS & the role of the UK Demonstration Programme The operation of the CCS chain has already been, and continues to be, demonstrated at 3Mte CO2/yr by

the Dakota Synfuels plant which has 10 years experience of operation of the full chain. The Synfuels

plant consists essentially of a syngas production unit which uses pre-combustion capture to produce a

decarbonised hydrogen rich syngas which at Dakota is used in the manufacture of synthetic natural gas.

In the power generation application, which is technically more straight-forward than synthetic natural gas

production, decarbonised syngas is combusted in a Combined Cycle Gas Turbine to produce electricity –

3Mte/yr of captured CO2 equates to a power plant of ~500MWe underlining that there no scale issues

associated with use of this capture technology and hence full scale commercial projects can be

constructed now63,64. However there are no clear reference plants for such Integrated Gasification

Combined Cycle Power Stations with capture. This first-of-a-kind risk makes the attraction of debt into

early projects challenging.

There are examples of CO2 storage in gas fields, oil fields and saline aquifers across the world, including

North Sea experience, although most injections are less than 1mte CO2/yr. This area has higher

uncertainties than the capture element and requires demonstration at large scale in the North Sea

environment for the different reservoir types available.

Hence technology exists, and whilst there are clearly substantial uncertainties, the challenge is for the

most developed options to move from the RD&D phase to early market applications. This is primarily an

issue of putting in place the appropriate commercial framework to enable the first of a kind risks and

uncertainties to be managed. Pre-combustion capture projects at say 400-800 MWe are possible now.

The captured CO2 can be stored, with the uncertainty being the scale of injection irrespective of reservoir

type. The UK has offshore oil fields, gas fields and saline aquifers which may be used for storage.

Storage in oil fields holds the prospect of providing the greatest value added as CO2 injection can be

used to recover otherwise unrecoverable oil – this is an established technique on-shore with c25-30mte

CO2 injected annually in oil fields in the USA for this purpose. However offshore experience is minimal at

present.

The Programme therefore needs to address the real first-of-a-kind uncertainties in the early CCS projects

even where the technology exists, notably full CCS chain reliability and large scale storage. It needs to be

on a basis which makes CCS a credible investment decision alongside renewables and gas CCGT.

Investment capital is limited for all candidate investors – including the major utilities and so the

demonstration programme needs to be structured to enable debt to be secured, and such that the widest

possible range of investors can be involved, as has been achieved for renewables.

63 In contrast other capture technologies suitable for power generation (post combustion and oxyfuel) have only operated at small scale and do require substantial scale up. 64 Pre‐combustion capture can also be used to repower existing coal power stations to utilise cost effectively existing assets with enhanced output compared with alternative refit options such as post‐combustion.


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In combination, the state of readiness of the technology and the opportunities for value creation support a

policy which seeks to introduce and deploy CCS in the UK as soon as possible. Clearly the current

financial environment limits what is affordable by consumers. However, even these first capture projects

will require less support than many other low carbon options.The overriding objective from this tranche of

4 CCS projects is not the demonstration of individual capture technologies, but must be to demonstrate

how to introduce CCS into the country’s economy to create long term value.

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