BEST PRACTICE BROCHURE

CARBON ABATEMENT

TECHNOLOGIES PROGRAMME

BPB009 AUGUST 2005

Co-firing of Biomass atUK Power Plant

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CONTENTS1. Introduction ........................................................ 11.1 Co-firing vs Dedicated Biomass Plant.................. 21.2 Descriptions of Relevant Plant............................. 4

2. Legislation .......................................................... 52.1 IPC Authorisations/IPPC Permits ......................... 6 2.2 Large Combustion Plant Directive (LCPD)........... 6

and Pollution Control2.3 Levy Exemption Certificates................................ 72.4 Renewables Obligation ........................................ 82.5 Renewables Obligation Auditing........................ 102.6 Waste Incineration Directive.............................. 112.7 Local Authority (Planning Consents) .................. 12

3. Commercial Issues........................................... 123.1 Fuel Compatibility .............................................. 123.2 Fuel Logistics ..................................................... 133.3 Ash Quality/Utilisation........................................ 14

4. Fuel and Plant Assessments........................... 144.1 Laboratory Testing ............................................. 154.2 Rig Testing ......................................................... 164.3 Single Mill Trials ................................................. 174.4 Full Unit Trials..................................................... 184.5 Design Studies................................................... 194.6 Plant Specification.............................................. 21

5. Technologies Used for Biomass Co-firing ..... 215.1 Fuel Blending Alternatives ................................. 215.2 Fuel Handling Plant ............................................ 225.3 Fuel Preparation Alternatives............................. 245.4 Modifications for Co-milling ............................... 255.5 Dedicated Burners/Injectors .............................. 255.6 Liquid Biofuels Equipment................................. 27

6. Health & Safety ................................................ 286.1 Health & Safety Reviews................................... 286.2 Dust and Biological Hazards ............................. 296.3 DSEAR ............................................................... 32

7. Future and On-going Developments ............. 327.1 Energy Crop and Co-firing Post-2009 ................ 327.2 Clarification of Longer-term Plant Impacts ........ 347.3 Co-firing Post-2016 ............................................ 35

8. Conclusions ...................................................... 35

9. References ........................................................ 369.1 Useful Web Sites ............................................... 369.2 Telephone Numbers........................................... 369.3 Contacts............................................................. 36

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1. INTRODUCTION

The Government has set ambitious targets for the country regarding reduction of CO2 emissions.One of the methods to reduce these emissions is co-firing of biomass with the considerable amountof coal that is currently burned by the UK powerindustry.

Biomass co-firing provides arelatively low-cost means ofincreasing renewables capacity,and an effective way of takingadvantage of the high thermalefficiency of large coal-firedboilers. It is also recognisedwithin the Government’sRenewables Obligation as aneffective means of stimulatingthe development of a market forbiomass fuels and energy cropswithin the UK.

The use of biomass as arenewable energy source isbeneficial to the environmentand can make a real contributionto the UK Government’srenewable targets andobligations. However, withouteconomic and politicalincentives it would be difficult tocommercially justify the on-going utilisation of biomass inthe UK, since biofuels aregenerally much more expensivethan conventional fuels, andhave significantly differentproperties with respect tostorage, bulk handling, volumeflow, milling, combustion,slagging, corrosion, and gaseousemissions.

In the UK, such incentives havebeen provided through theissuing of Renewable ObligationCertificates (ROCs) and to alesser extent Levy ExemptionCertificates (LECs), for powerproduced by co-firing biomass.As a result, many of the utilitycompanies in the UK havedeveloped projects that takeadvantage of these incentives,as indicated by Table 1. Factorsthat will potentially influence thecontinued utilisation and furtheruptake of biomass co-firing in thefuture include higher fossil fuelprices and the value of carboncredits under the EU’s EmissionsTrading Scheme (ETS).

BEST PRACTICE BROCHURE:

Co-firing ofBiomass at UKPower Plant

Images courtesy of E.ON UK plc

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This experience has raised issues in a numberof areas which lead to complications duringplant design, construction and commissioning.Consequently, there is a large amount ofexperience and information regardingcombustion and co-combustion of biomassavailable in the UK, and through the links thathave been developed with a range oforganisations involved in these activitiesworldwide.

Through the DTI, the Government is alsosupporting a number of initiatives related to theco-firing of biomass at power stations.Although these projects include elements ofdissemination, by themselves they aresomewhat fragmented, with overall reportingtimescales that are significantly longer thanhave been achieved with this brochure.

This Best Practice Brochure1 summarises theexperience derived from all the currentbiomass co-firing activities in the UK. It isdesigned to disseminate relevant informationbetween all those involved in biomass co-firing

activities, and to speed up the implementationof the most successful methods. It providesdetails of the solutions that have been adoptedto the issues encountered, along with acommentary on those issues that still need tobe resolved as further projects are developed,and the market drivers change towards theutilisation of energy crop and dedicatedbiomass combustion plant.

1.1 Co-firing vs DedicatedBiomass Plant

There are two main options available forutilising biomass as a renewable energy sourcein the generation industry: construction of‘stand-alone’ dedicated biomass plant, or co-firing of biomass with other fuels in existingcombustion plant.

Stand-alone or dedicated biomass plants aredefined in the Renewables Obligation as thosewhich have been commissioned since 1 January 1990 and are fuelled wholly bybiomass in any month, although fossil fuel or

Table 1. Biomass co-firing in the UK

TotalStation capacity Generator Status Biomass fuels

(MWe)

Aberthaw 1,455 RWE npower Commercial VariousCockenzie 1,200 ScottishPower Commercial WoodCottam 2,000 EdF Commercial VariousDidcot 2,100 RWE npower Commercial WoodDrax 4,000 Drax Power Commercial VariousEggborough 1,960 British Energy Commercial VariousFerrybridge 2,035 Scottish & Southern Commercial VariousFiddler’s Ferry 1,995 Scottish & Southern Commercial VariousIronbridge 970 E.ON UK Commercial VariousKingsnorth 2,034 E.ON UK Commercial VariousLongannet 2,400 ScottishPower Commercial Waste-derived fuelRatcliffe 2,010 E.ON UK Commercial VariousRugeley 1,000 International Power Commercial VariousTilbury 1,085 RWE npower Commercial WoodWest Burton 1,980 EdF Trial Olive cake

1 A comprehensive report (Report No. COAL R287, DTI/Pub URN 05/1160) is available from the DTI website(http://www2.dti.gov.uk/energy/coal/cfft/cct/pub/reports.shtml)

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waste (eg residual fuel oil) can be used forcertain purposes (eg ignition, stabilisation,emission control, stand-by) on a dedicatedbiomass plant. The Obligation also allows plantcommissioned prior to 1 January 1990 to beused as dedicated biomass plant, provided thatcertain conditions are met with regard tocurrent biomass utilisation.

It is possible to optimise a stand-alone biomassplant at the design stage, and therefore allowfor any peculiarities specific to the fuel to beburned. In this way, dedicated plants presentan advantage over co-firing biomass on anexisting plant, where the plant design andsystems will have been optimised for theprimary fuel.

Planning, design, authorisation, constructionand commissioning of new dedicated biomasspower plants can take a number of years andinvolve significant costs. Capital and operatingcosts are typically orders of magnitude higherthan for co-firing schemes of similar capacityand hence payback periods are significantlylonger. This increases the reliance of dedicatedbiomass schemes on renewables supportmechanisms and associated capital grantschemes. Investor confidence in the long-termsecurity of such mechanisms is also clearlyessential for dedicated biomass development.Only one dedicated biomass schemedeveloped in the context of the RenewablesObligation has to date entered construction. Itis, however, noted that others, includingE.ON’s 43MWe Lockerbie project, are in thefinal stages of development.

On the other hand, existing fossil fuel-firedpower stations can quickly be modified for co-firing and achieve considerable levels ofrenewable generation, with lower capital costsand less commercial risk. The directdisplacement of coal when co-firing plus thehigher conversion efficiencies generallyachieved also contribute to higher CO2reduction benefits from each co-fired tonne ofbiomass. Further modifications could be madeto enable the use of a broader spectrum ofless processed biomass fuels, if in the longerterm financial incentives were sufficient tojustify this.

Initially, off-site ‘pre-blending’ with coal(particularly at load ports or railheads) wasfavoured by many generators due to theinvestment required to install equipment foron-site blending. However, Ofgem hasconcerns regarding the ability of generatorsinvolved in pre-blending to fulfil themeasurement and sampling requirements ofthe Renewables Obligation. In particular, theseconcerns relate to perceived risks of biomassfuels deteriorating in transit to the site, and theaccuracy with which blends can be analysed todetermine the biomass content at thegenerating station. Consequently, co-firedgenerators have been blending on-site orutilising direct injection routes.

Throughout the development of the legislation,the relatively short period of eligibility for co-firing under the Renewables Obligation hasfavoured low capital expenditure schemes withshort lead times. For coal-fired plant, on-siteblending of biomass with the primary fuel priorto co-milling has proved to be the least capitalintensive approach, and is currently the mostpopular method for co-firing in use in the UK’slarge coal-fired power stations listed in Table 1.

Figure 1. Ironbridge Power Station (courtesy of E.ONUK plc)

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1.2 Descriptions of Relevant Plant1.2.1 Introduction to Coal-fired Power

StationsIn the UK, the term ‘coal-fired’ is used to referto power stations which burn a range of solidfossil fuels in boilers to heat water, therebyproducing high-pressure, high-temperaturesteam. The steam is used in turbine-generatorsto produce electricity, which is measured inunits of megawatts (MW).

The typical layout of a large power station inthe UK comprises a number of units, eachconsisting of a boiler, a turbine-generator set,and ancillaries (see Figure 2).

The range of fuels burned in modern coal-firedpower stations vary widely in terms ofchemical composition and physical properties.

Prior to combustion, fuel particle size isreduced in pulverising mills to a fine powder(‘pulverised fuel’) which is pneumaticallyconveyed to the furnace where it burns morerapidly, completely, consistently andcontrollably than could be achieved with thedelivered feedstock.

The pulverised fuel is burned with controlledquantities of air to achieve the desiredcombustion behaviour necessary to achievethe required efficiency and environmentalperformance. The boiler walls are constructedfrom tubes in which water is heated to

produce steam. ‘Superheat’ and ‘reheat’sections of the boiler allow a range oftemperatures and pressures to be achievedand maximise the efficiency of the steamraising process.

All coals contain organic and inorganicfractions. The non-combustible inorganicfraction (‘ash’) is collected from the base of theboiler (‘bottom ash’) and from the exhaust gasstream (‘fly ash’). Much of this ash is utilised inother industries, such as cement productionand road surfacing.

At the high temperatures inherent withcombustion in a boiler, the organic fraction ofthe fuel reacts with air to produce a range ofgases (collectively termed ‘flue gas’) includingoxides of nitrogen (NOX) and sulphur (SOX), andcarbon dioxide. After passing through heatrecovery stages and having the fly ashremoved in electrostatic precipitators, the fluegas is exhausted from the boiler to theatmosphere via the chimney stack.

Most power stations have some form ofemissions control equipment to mitigate theirenvironmental impact. This may be in the formof optimised hardware, fuel additives, processcontrol systems or exhaust gas treatment,which in a number of cases now includes fluegas desulphurisation (FGD) in addition toelectrostatic precipitators.

Stack

Electro-StaticPrecipitator

Boiler Tubes

Furnace

Combustion System

Milling Plant

Fuel Stock

Flue GasDe-Sulphurisation

Figure 2. Typical power station boiler system (courtesy of E.ON UK plc)

Stack

Flue gas desulphurisation

Boiler tubes

Furnace

Combustion system

Milling plant

Fuel stock

Electrostaticprecipitator

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Table 2 provides typical technical data for coal-fired power plant in the UK:

1.2.2 Co-milling of BiomassThe approach that has currently been adoptedto biomass co-firing in most coal-fired powerstations in the UK is to pulverise the coal andbiomass simultaneously in the existingpulverising mills. This approach has beentermed ‘co-milling’, and it allows thesimultaneous size reduction and drying of boththe biomass and coal, prior to the two fuelsbeing burned together in the furnace.

Where a co-milling approach is adopted, thebiomass and coal may be blended before orafter delivery to the power station. The formeroption is referred to as ‘off-site blending’, andresults in a single fuel stream to the powerstation, which can be handled in a similar wayto coal. The latter option is referred to as‘on-site blending’; where two fuels aredelivered to the power station, and requireseparate reception and handling facilities upuntil the point where the two fuel streams are blended into one. All stations that are co-milling biomass in the UK are using on-site blending to satisfy Ofgem’s auditrequirements.

Unit sizes MW Up to 660

Unit efficiency % Up to 40%

EmissionsNOX mg/Nm3 500 to 650

SOX mg/Nm3 ~500 (with FGD*)~2000 (no FGD*, low S coal)

CO2 tph 280 to 580tCO2/MWh 0.88 to 0.99

Carbon-in-ash % 2 to 20

*FGD = flue gas desulphurisation

Table 2. Typical technical data for UK coal-fired powerplant

1.2.3 Direct Injection‘Direct injection’ offers an alternative route forsupplying co-fired biomass to a coal-fired boiler.It involves the introduction of the biomass tothe boiler in a separate stream, throughseparate burners/injectors. This providesseveral advantages over co-milling, the mostsignificant being that the biomass does notaffect the flow, milling and classification of thecoal, and it avoids the unit load limitations thatcan occur when co-milling with low calorificvalue coals or biomass. However, this type ofinstallation is much more capital intensive thanthe limited modifications required for a co-milling approach.

The separate handling of biomass also allowsco-firing to be carried out in a plant that hasstrict limits on volatile content in the coal.Biofuels typically contain around 80% volatilematter (on a ‘dry ash free’ basis), whereascoal-fired plant in the UK are designed toreceive coals with dry ash free volatilecontents of less than 45% for bituminous coalsand 10% for anthracitic coals. This separatehandling also has the advantage that problemsthat would occur when materials with badmilling properties are sent through the mill canbe effectively bypassed.

Installations for direct injection schemes haveranged from a simple hopper feeding apneumatic transport line leading directly intothe furnace, to elaborate chipping/grindingplant feeding separate biomass burners with acomplete burner control system.

2. LEGISLATION

All companies have an impact on theenvironment and as such are morally and legallyresponsible for managing these effects - andenvironmental legislation has been developedover the years to ensure that any impact stayswithin acceptable limits. Environmentallegislation tends to be complex and constantlychanging. In recent years, the volume oflegislation concerned with the environment hasalso increased significantly, and an overview ofthis legislative framework and its implicationsfor biomass co-firing is provided here.

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There are now a number of EU Directives ofdirect relevance to the power industry. Forexample, the Integrated Pollution Preventionand Control (IPPC) Directive specifies that BestAvailable Techniques (BAT) for minimisingpollution should be determined for variousindustry categories, including LargeCombustion Plant. The European PollutantEmission Register (EPER), established by aseparate decision, under the umbrella of theIPPC Directive, requires Member States toreport national emissions of listed pollutants.

In addition to the Renewables Obligation (RO),environmental legislation that has beenenacted in the UK which makes specificreference to the use of biomass fuels in powerstations includes the Large Combustion PlantDirective (LCPD), the Climate Change Levy(CCL), and the Waste Incineration Directive(WID).

Also, the alteration of activities in any industrycan involve verification of local planningapplications to ensure that all permissions areadhered to. Naturally, the same requirementsexist for the power industry and, as such, theissues that have been raised as a result of co-firing activities are also considered here.

which will contain conditions that they mustadhere to.

Throughout the UK, ‘Integrated PollutionControl’ (IPC) is being phased out and replacedby the ‘Pollution Prevention and Control’ (PPC)regime. This implements the EU’s ‘IntegratedPollution Prevention and Control’ (IPPC)Directive within the UK, and builds on many ofthe same principles as IPC. Under PPC, powerstations are classed as ‘Energy IndustryCombustion Activities’ and fall within the PartA(1) process category. Permits issued underPPC must be based on the Best AvailableTechniques (BAT), taking into account the localenvironmental conditions, geographical locationand technical characteristics of the specificinstallation.

PPC includes new issues not previouslycovered by IPC such as vibration, noise, wasteminimisation and energy efficiency. This newsystem also requires that an effectivemanagement system is in place to ensure thatall pollution prevention and control measuresare taken.

Before burning biomass material, allcombustion plant operating under IPC/IPPCneed to apply for approval from theEnvironment Agency (EA). These applicationsare made through local EA Area Inspectors,and for the earliest biomass co-firingapplications this led to some inconsistency inapproach to the approvals given. The EA andthe Joint Environmental Programme (JEP)subsequently worked together to produce aprotocol for the approval process. This protocolhas helped to standardise the approvals foroperators and also allowed some streamliningof the process.

2.2 Large Combustion PlantDirective (LCPD) and PollutionControl

The revised Large Combustion Plant Directive(LCPD) is particularly important since thisestablishes emission limit values (ELVs) fornew and existing plant, in addition to makingfurther provisions for pollution inventoryreporting in support of the European Pollutant

Figure 3. Cottam Power Station (courtesy of E.ON UKplc)

2.1 IPC Authorisations/IPPCPermits

The Environmental Protection Act 1990 and theIndustrial Pollution Control (Northern Ireland)Order 1997 have created a UK-wide pollutioncontrol system for industry where any personcarrying out a prescribed process must obtainauthorisation from the environmental regulator

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Emission Register (EPER) requirements.However, it should be noted that it isnecessary to satisfy the requirements of boththe LCPD and the IPPC Directive.

Under this legislation, existing combustionplant must either observe lower emissionlimits, or achieve equivalent emissionreductions via a national emissions reductionplan, by 2008, unless it is intended to close theplant after a further 20,000 operating hoursbetween 2008 and the end of 2015. Plant thatis upgraded to meet the Part A Emission LimitValues, defined in the Annexes of theDirective, is ‘opted in’. Plant that is designatedfor eventual closure is ‘opted out’.

The LCPD limit values for existing and newplant larger than 300MWth are given in Table 3.There are specific requirements for bothmonthly averages and 48-hour averages, andnumerous caveats within the text of theDirective. Continuous emissions monitoring isrequired for all plant greater than 100MWth andthe LCPD also requires compliance with CENstandards relating to the quality assurance ofthese monitoring systems.

Since 2004, each large combustion plant mustalso report an inventory of total annual SO2,NOX and dust emissions and the total annualenergy input and net calorific value by fueltype. Biomass is identified as a separate fuelcategory, in common with the provisions of theEU Guidelines for the Monitoring andReporting of Greenhouse Gas Emissions.

The LCPD defines biomass as any productconsisting of vegetable matter from agricultureor forestry which can be used as a fuel for thepurpose of recovering its energy content. TheLCPD also includes a list of biomass wastesthat are exempt from the provisions of theWaste Incineration Directive (see Table 4).

2.3 Levy Exemption Certificates

As part of a range of measures to help the UKmeet its commitment to reduce greenhousegas emissions and create a low carboneconomy, the UK Government introduced theClimate Change Levy (CCL) on industrial andcommercial (I&C) users in April 2001. Under this scheme, I&C users of electricity

Existing (Part A)* New (Part B)Fuel Type Solid Liquid Gas Solid Liquid Gas

SO2 400 400 35 200 200 35

NOx 500 400 200 200 200 100

Dust 50 50 5 30 30 5

Ref. O2 dry 6% 3% 3% 6% 3% 3%

Table 3. Nominal LCPD emission limit values for large plant (>300 MWth)

* Valid until 31 December 2015

• Vegetable waste from agriculture and forestry

• Vegetable waste from the food processing industry (with heat recovery)

• Fibrous vegetable waste from virgin pulp and paper production from pulp, if it is co-incinerated atthe place of production and the heat generated is recovered

• Cork waste

• Wood waste with the exception of wood waste which may contain halogenated organiccompounds or heavy metals as a result of treatment with wood preservatives or coating, andwhich includes, in particular, such wood waste originating from construction and demolition

Table 4. Biomass wastes that are exempt from the provisions of the Waste Incineration Directive

NB List limited to Renewables Obligation biomass likely to be co-fired in fossil fuel-fired plant. See the WasteIncineration Directive (Article 2, Paragraph 2) for the complete list.

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must pay an additional £4.30/MWh for theirelectricity. Payments are made to HM Revenue& Customs (HMRC) and partly administered byOfgem. These payments can be avoided byeither investing in energy efficient machinery(80% rebate), or purchasing a Levy ExemptionCertificate (LEC) as evidence of havingconsumed a unit of electricity (1 MWh)generated using renewables (100% rebate). Itis generally thought that the I&C user isprepared to pay up to £4.00/MWh to theelectricity supplier for an LEC which enables itto avoid paying £4.30/MWh to HMRC and thatthe electricity supplier in turn would pay up to£3.40/MWh for a renewable LEC to thegenerator, meaning that the electricity supplieris the essential link. The final value that thegenerator receives for renewable LECs issubject to negotiation and is market-based, andtherefore unstable until contract completion.

In addition, the EU Emissions Trading Scheme(ETS) was launched on 1 January 2005. Both ofthese measures may award value to renewablegenerators, because renewable generation isexempt from the CCL and from the EU ETS.

The CCL exemption can be traded throughLECs, whereas carbon values from the ETS arelikely to be passed on through higherwholesale electricity prices.

2.4 Renewables Obligation

The Renewables Obligation was introduced on1 April 2002, and extended to Northern Irelandin 2005. It is effective until 31 March 2027 andhas the following goals:

● Increasing the amount of electricitygenerated from renewable energy sourcesto 15.4% of total supply in 2015

● Reducing carbon dioxide emissions● Maintaining investor confidence in the

development of renewable energy sources● Development of an integrated UK biomass

production and utilisation industry.

It requires all licensed electricity suppliers inthe UK to supply a specified proportion of theirelectricity sales from a choice of eligiblerenewable sources, and provides a number ofpaths to compliance. This is the key instrument

Figure 4. A photo-montage of renewable energy projects (images courtesy of E.ON UK plc)

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the Government is using to influence thegrowth necessary to reach the UK’s renewableenergy targets in the power sector.

The Renewables Obligation defines a numberof eligible renewable energy sources whichinclude combustion of biomass in dedicatedplant; co-firing of biomass and energy crops(subject to the restrictions detailed in Table 5);and pyrolysis, gasification & anaerobicdigestion of biomass and biomass/wasteblends (such plant can only claim RenewableObligation Certificates (ROCs) for the biomasscomponent of mixed waste). For the purposesof the Renewables Obligation, biomass isdefined as a “fuel from which at least 98% ofthe energy content is derived from plant oranimal matter”.

ROCs are awarded for eligible renewablegeneration from the above technologies. Inorder to limit the impact of large-scale co-firingon the ROC market, restrictions have beenplaced both on the fuels used at co-fired

stations and on an electricity supplier’s abilityto demonstrate compliance with theRenewables Obligation using co-fired ROCs(the ‘Co-firing Cap’).

An additional restriction on fuel type is thatfrom 2009 onwards an increasing proportion ofthe fuel used for co-firing will have to besourced from energy crops. This is alsodesigned to encourage the development ofindigenous supplies of this feedstock. Energycrops are defined as crops planted after 31December 1989, and grown primarily for thepurpose of being used for fuel.

Details of the other targets and restrictions onco-firing, as they are currently defined, are setout in Table 5.

The Government is currently reviewing thelegislative framework that should be put inplace beyond 2015. It has said that no majorchanges that will create uncertainty for projectdevelopers will be undertaken.

Table 5. Targets and restrictions on co-fired renewable generation

Year Estimated UK Predicted Proportionsales by Suppliers’ Total maximum of co-firinglicensed obligation obligation Co-firing co-fired to besuppliers (% (TWh) cap (%) ROCs energy

(TWh) renewables) (TWh) crop (%)

2001/2002 310.9 * 25 -

2002/2003 313.9 * 3.0 9.4 25 2.4 -

2003/2004 316.2 * 4.3 13.5 25 3.4 -

2004/2005 318.7 * 4.9 15.6 25 3.9 -

2005/2006 320.6 * 5.5 17.7 25 4.4 -

2006/2007 321.4 * 6.7 21.5 10 2.2 -

2007/2008 322.2 * 7.9 25.4 10 2.5 -

2008/2009 323.0 * 9.1 29.4 10 2.9 -

2009/2010 323.8 * 9.7 31.5 10 3.2 25

2010/2011 324.3 † 10.4 33.6 10 3.4 50

2011/2012 325.2 † 11.4 37.1 5 1.9 75

2012/2013 326.0 † 12.4 40.4 5 2.0 75

2013/2014 326.7 † 13.4 43.8 5 2.2 75

2014/2015 327.5 † 14.4 47.2 5 2.4 75

2015/2016 328.2 † 15.4 50.5 5 2.5 75

* Source = DTI † = Extrapolated data

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2.5 Renewables ObligationAuditing

Under the Renewables Obligation Order,Ofgem is only authorised to issue ROCs onceit is satisfied that a number of relevant criteriahave been met. Consequently, as well asoperating routine checks and controls, Ofgemcarries out audits each year on a sample ofgenerating stations.Ofgem carried out 20 audits of accreditedgenerating stations during the first obligationperiod. The sample size has been increased in

misinterpretation, Ofgem encourages thesubmission of a proposed ROC claimsprocedure prior to commencing co-firing, and is willing to meet with generators todiscuss how the biomass measurementrequirements can be fulfilled at each station. It is noted that due to concerns regardingcommercial confidentiality, RO proceduresoperating at existing biomass sites are nottransparent.

Whilst the fundamental principles establishedwithin the legislation are clear, the implicationsof the detailed requirements for biomass sitesare not immediately apparent. Additionalguidance on Ofgem’s interpretation of theserequirements is, however, available on itswebsite.

Given the complexities of the Orders, it mightbe expected that biomass generators wouldexperience some difficulties at the start of thescheme and the audit findings to date seem tobear this out. Where misunderstandings anddisputes have arisen, the absence of anappeals mechanism under the RenewablesObligation and the lack of transparency have, inmany cases, compounded issues experiencedby generators.

Where a claim satisfies Ofgem’s requirementsfor accuracy and reliability, ROCs will be issuedapproximately one month after the deadline forsubmission (three months after the month ofburn). However, the administrativerequirements of the Renewables Obligation forbiomass utilisation and the complexity of theprocesses involved should not beunderestimated. The requirements may alsochange with time, and the onus is on thegenerator to monitor for these changes andrespond accordingly.

Where there are problems with a ROC claimprocedure this may not come to light until afterthe ROC claim is processed (up to threemonths after generation), and it may be someconsiderable time before the issue can beresolved to Ofgem’s satisfaction.Consequently, in a number of cases,generators have built up large financialliabilities with respect to their ROCs claims.

Figure 5. Managing the process (courtesy of E.ON UKplc)

subsequent years and will be maintained at alevel deemed necessary to ensure the integrityof the scheme. Whilst most of the outcomeswere satisfactory, some recurring issues didarise, mainly with regard to interpretation ofterms used within the Renewables Obligationand the methods used for calculating thenumbers of ROCs claimed.

The requirements that need to be met to claimfor co-fired ROCs are contained in theRenewables Obligation Order 2005. Thisreplaced the Renewables Obligation Order2002 and the Renewables Obligation(Amendment) Order 2004. The updates to thelegislation were designed to addressunforeseen operational difficulties and toensure the Renewables Obligation delivers itsrenewable targets.

Generators are advised to read thesedocuments with care. To avoid

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2.6 Waste Incineration Directive

The Waste Incineration Directive (WID) hasapplied to all new waste incinerationinstallations since 28 December 2002 andapplies to all existing installations co-firingcertain wastes from 28 December 2005.

The purpose of the directive is to limit orprevent, as far as practicable, negative effectson the environment, in particular, pollution byemissions into the air, soil, surface water andgroundwater, and minimise the resulting risksto human health from the incineration and co-incineration of waste. The directive willrequire the setting and upholding of stringentoperational conditions, technical requirementsand emission limit values for plants incineratingand co-incinerating waste throughout theEuropean Union, to achieve a high level ofenvironmental and health protection.

Under the Renewables Obligation, ‘biomass’ isdefined as a material in which at least 98% ofits energy content is derived from plant oranimal matter when it is used as a fuel. Thismay include the co-firing of waste (egmunicipal solid waste fractions) to produceROCs – as long as the waste materials meetthis definition.

Figure 6. A wall-fired burner flame (courtesy of E.ONUK plc)

Generating stations may fire unadulterated,plant-derived, biomass products and by-products without reference to the WID. Theymay also fire plant-derived biomass waste thatis WID exempt (see Table 4 and Article 2,Paragraph 2 of the Directive). Both are eligiblefor ROCs. However, if a biomass waste is notWID exempt, the station would be subject tosome of the additional requirements specifiedby the WID, eg much more stringent airemission limit values, reduced flexibility withregard to operating conditions, additionalmeasures relating to water discharges fromexhaust gas cleaning, ash recycling, plantcontrol and monitoring, and public access toinformation. It is, therefore, generallyuneconomic for an existing generating stationto burn biomass that is not WID exempt.

The Environment Agency has confirmed that allof the plant-derived biomass materials co-firedin the UK to date are exempt from the WIDeven if these could be classified as wasteunder some circumstances.

Given the broad EU definition of a waste as“any substance... which the holder discards orintends or is required to discard”, there is aconcern that certain biomass types that maynot be traditionally viewed as such, could beclassified as wastes, requiring compliance withthe Waste Management Regulations. Thiscould, therefore, apply to some materials thatare exempt from the provisions of the WID.

Classification of biomass as a waste, evenwhen WID exempt, may result in substantiallyincreased costs arising from compliance withthe Waste Management Regulations, andindividual organisations will have to verify theirDuty of Care requirements for thetransportation of such biomass fuels. This mayhave a significant negative impact on thesupply of biomass as a renewable energysource.

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2.7 Local Authority (PlanningConsents)

Development consent for new electricitygenerating stations over 50MWe is requiredunder Section 36 of the Electricity Act 1989.

To date, experience of biomass co-firing in theUK suggests that the Department of Trade andIndustry does not consider these changessufficient to require Section 36 Consent underthe Electricity Act 1989, despite all suchschemes involving some extension of powerstation facilities and some change in operation.However, operators should satisfy themselvesthat Section 36 Consent exists or is notrequired for their schemes.

In addition, the Town and Country PlanningOrder permits certain developments forelectricity generating purposes by generationlicence holders, and a biomass co-firingscheme can often be installed under thesepermitted development rights without specificplanning permission.

If these rights are used, the height of any newbuilding or structure must not exceed 15metres above ground level or the height of anystructure replaced, and a number of otherrestrictions also apply. It should always bechecked that the local authority agrees thatconstruction as part of a co-firing scheme is apermitted development.

Permitted development rights do not apply if aproject needs an environmental impactassessment (EIA). If the area involved is over0.5ha or the site is in a ’sensitive area’ then thebiomass scheme will be a ’Schedule 2development’ under the Planning EIARegulations, for which EIA may be required atthe discretion of the local planning authority.

3. COMMERCIAL ISSUES3.1 Fuel Compatibility

The economic benefits of biomass co-firing caneasily be outweighed by the commercialimplications of any adverse impacts on load

capability, particularly where there is a need toachieve flexibility with respect to overall plantoperation. This makes assessing thecompatibility of any particular biomass fuel anextremely important aspect of the fuelprocurement process.

The impact that a biomass fuel has on plantoperation will be dependent on the type ofplant involved, especially the configuration ofthe milling plant if the biomass is to be co-milled, and the range of coals with which

Figure 7. Biomass fuels (courtesy of E.ON UK plc)

the biomass is to be co-fired.Basic assessment of any new biomassmaterial proposed for a particular plant istypically carried out through a combination ofstandard fuel analysis techniques, single milltesting and full unit trials. In this way, thefollowing aspects of each fuel are assessedwith respect to the co-firing approach to beutilised for commercial biomass co-firingoperations:

● Fuel analysis, particularly the calorific valueof the fuel, its moisture content, its volatilematter content (used to provide a measureof the reactivity of the fuel and the level ofrisk associated with blending it with highervolatility coals), and its trace elementcontent (which must lie within limiting levelsagreed with the EA).

● Bulk handling characteristics in terms ofdust generation, mechanical stability andodour.

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● Compatibility with existing plant, particularlythe bunkers, feeders and milling plant(where the biomass is to be co-milled),taking into account the impact that eachbiomass fuel has had on mill throughput,and how this varied with the proportion ofbiomass blended with the coal.

● Combustion characteristics, particularly fuelburn-out, due to the adverse impact poorburn-out has on electrostatic precipitatorperformance, fly-ash sales, and overall plantefficiency.

Completion of this evaluation process willoften result in a very limited range of fuelsbeing considered suitable for any particularbiomass co-firing application. Experience has,however, shown that the range of fuelsselected will be plant specific and dependenton a number of factors including the requiredco-firing levels, the operating regime at theplant, the design and general condition of thefuel handling and milling systems, and therange of coals with which the biomass is to beco-fired.

Clearly, such limitations can restrict theflexibility of biomass co-firing operations.Where this is seen as a limiting factor in thepotential commercial success of co-firing, thereare a number of improvements which can bemade to increase the co-firing capability andwiden the range of biomass fuels that can besuccessfully co-fired on a commercial basis. Inmany cases, however, these improvementsresult in higher capital and revenue costs,particularly where there is HSE involvement inthe resolution of occupational health and safetyissues associated with these operations.

3.2 Fuel Logistics

Typical fuel choices for co-firing have been’clean’, plant-derived biomass (eg wood pellets,palm kernel, pelletised cereal co-product).Fuels of this type have been selected to beWID exempt and to satisfy Ofgem’srequirements with respect to verification offuel purity.

In addition, the selection of fuels for a specificsite is governed by fuel consumption rates,security of supply issues, stocking policies,reserve stocks, and transportation issues.Having considered these issues, the value ofeach selected biomass fuel can then beassessed. This assessment will depend on anumber of factors, including relative price,availability, achievable blend ratio, calorificvalue, additional handling and blending costs,and technical or health and safety risks.

Evaluation of these factors is likely to furtherreduce the range of biomass fuels that can beutilised at a particular site, and in many caseshas led to the identification of one preferredfuel, or even eliminating co-firing as an optionwithout additional capital investment toimprove the systems and increase fuelflexibility.

Figure 8. A Miscanthus crop (courtesy of BiomassIndustrial Crops Ltd)