Co-combustion of biomass with coal - the advantages and disadvantages compared to purpose-built biomass to energy plants. Mitverbrennung von Biomasse in Kohlekraftwerken: Vor- und Nachteile im Vergleich zu Biomassekraftwerken Richard Hotchkiss, Dorian Matts, and Gerry Riley. InnogyOne Innogy PLC Windmill Hill SWINDON SN56PB UK Tel 00441793896264 email richard.hotchkiss@innogy.com SYNOPSIS The economics of two options for electricity generation from biomass are considered using simple models. The options considered are cofiring biomass with coal in an existing pulverized fuel power plant and building a plant specifically for biomass. The major issues and risk areas for the two options are discussed. InnogyOne carried out a plant specific appraisal of the economic and engineering issues associated with cofiring a significant proportion of biomass in a large coal fired power plant, 3 x 350 MWe units. (Financial support for this work was provided by DTI through the Cleaner Coal Technology R&D Programme managed by Mott MacDonald). Information was obtained on a 0.5 MWt combustion test facility and associated fuel properties tests. The power plant chosen for the study had attractions compared to other power stations in Innogy's portfolio but the economic evaluation was unable to identify an adequate return on the investment being considered. A lower capital cost option for firing wood at a lower ratio of wood to coal was investigated. Appropriate permits were obtained and power plant trials were performed. THE RENEWABLE OBLIGATION CERTIFICATE (ROC) SYSTEM FOR ELECTRICITY IN ENGLAND AND WALES The UK government introduced incentives for the Electricity Supply Industry in England and Wales to use renewable sources of electricity as part of a strategy to reduce fossil fuel

derived CO2 emissions. This is a target-based penalty and reward system imposed on suppliers of electricity, not generators. Suppliers not achieving targets for supplying electricity from renewables will pay 3p/kWh, about €c4.5/kWh, levy. This levy is pooled and Renewable Obligation Certificates (ROCs) are obtained by suppliers of electricity from renewable sources. This gives generators of renewable electricity additional income from the pooled monies and hence increases the value of the (tradable) ROCs above the 3p/kWhr. The uncertain value of green tickets makes it difficult to evaluate the value for investment. Therefore, low capital investment schemes are inherently less risky at present (this applies to all investment in generation assets), particularly as the financial margins in power generation in the UK are currently very small or negative even excluding capital charges.

The Government sets indicative targets for each year for the proportion of electricity from renewables rising to 20% by 2020 (1). It indicated its expectations of the renewable mix (2) with over 20% of the renewable electricity expected from biomass by 2010. However the ROCS and particularly the pooled money for return for biomass generation is not separated from other forms of renewable generation (e.g wind or small hydro) which appear to be financially more attractive in the longer term. Key aspects of the competing renewable technologies are shown in table 1. Table 1

England and Wales system of Renewables Obligation Certificates (ROCs)

(4.5€c + 2.2€c? + 2.2€c?)

England and Wales system of Renewables Obligation Certificates (ROCs)

(4.5€c + 2.2€c? + 2.2€c?)

Capital cost

Location, location and location

Hydro (small)

Average / peak output ratio

Capital cost.Availability.Zero fuel cost

Expensive fuel. High capital cost of new plant

Capital costWeather and consents

Cost and consents dominate

PVWindBiomass

All technologies compete for ROCs All qualifying technologies attract the same level of green ticket income on a MWh generated/sold basis. The Renewables Obligation Order 2001, enacted under the Electricity Act (1989) differentiates the eligibility of biomass based generation for Green Tickets on the basis of how it is produced, even through the effect in the emissions of

CO2 may be the same. Biomass is eligible for Green Tickets if used in dedicated biomass plants (>75% biomass) or if co-fired with other fuels, e.g. coal. FUTURE REGULATORY CHANGES From 2006 there will be additional restrictions on biomass that qualifies for ROCs. This effectively means that at least 75% of wood cofired after 2006 has to come from purpose-planted biomass energy crops after March 2006. Wood in the UK can be classified as fuel rather than as waste even if it was not planted with the intention of using it as fuel. However used wood and many other biomass fuels are or will be classified as wastes. Wastes will be covered by a new waste incineration directive (WID) from 2005. The WID will impose tighter constraints on operation of power plants using wastes and will also impose lower limits on emissions, including NOx and SOx) for such plants. Major changes in the European agricultural support mechanisms including “set-aside” are expected to be introduced in 2006. Uncertainty in the post 2006 agricultural economic structure are of serious concern to farmers considering planting energy crops, particularly arable coppice that is linked to set-aside quotas on arable farms. Arable coppice differs from most agricultural crops in the long time periods between sowing and harvesting, the period of several years between each harvest and the need for long-term commitment to recover the investment. In contrast, conventional grain farming works on cycles of less than 12 months between planting and final harvest. This needs a different financial support mechanism. To obtain financial support in the UK, a farmer needs a contract with a power plant within an acceptable distance (normally 30km) of the crop. The difficulties in getting long term agreements so that crops can be planted and power plant projects started so that power plant and crop is ready at the same time are obvious. The situation is further complicated by the difficulties power plants have experienced in obtaining planning permission or proceeding through construction and commissioning to commercial operation have left many arable coppice growers with crops for which the intended power plant is unavailable. It is difficult to see how the arable coppice industry can produce significant quantities (compared to electricity generation fuel requirements) of purpose grown fuel wood by 2006 even if a major UK planting programme were to start today. The biological timescales between tree planting and wood harvesting are well known. Those involved in agricultural and forestry operations prefer to spread planting and harvesting operations over the years instead of investing more intensively in labour and machinery used only in seasons separated by a few years. The supply of purpose-grown biomass cannot easily be changed stepwise from almost zero to sufficient for even a single local power plant. With coppice harvesting likely to be on a cycle of about 3 years, the fuel supply for 2007 and 2008 may not match that in 2006. These difficulties and risks influenced the Innogy decisions discussed later in this paper.

ECONOMICS OF STAND-ALONE BIOMASS POWER PLANTS

Power generation plants fired solely by biomass are small compared with conventional coal, gas, oil or nuclear stations. This size depends on biomass growing capacity and delivery. Transport of biomass, a material with a low bulk energy density is expensive when conveyed over the long distances to larger plants. The traffic involved may also be a major local concern. Specific capital cost, efficiency and specific operational cost advantages of larger power plants are balanced against fuel transport issues. Optimum plant sizes are still the subject of debate, proposals for biomass-only power plant rarely exceeding 50 MWe. Restricting plant size to about 20 MWe results in an installed specific capital cost of about €2250/kWe, considerably more expensive than coal plants and about 5 times that for large-scale gas fired generation. This price reflects both the absence of economies of scale and the technology complexities. There are reports of a turnkey order for 3 x 20 MWe wood fired power plants in Germany as low as €1875/kWe (3) or €2000/kWe (4) which corresponds to a capital cost, including financing during construction, close to that assumed here.

Small power plants can be based on gasification or combustion technologies. The former

are higher capital cost, less well proven and less widely used than the latter and generally require additional project-specific or technology-specific financial assistance. Combustion systems use a steam cycle and a steam turbine. At the sub-50 MWe size the steam cycle has to be relatively simple and the authors are unaware of any units of this size using steam reheat (although one at 20 MWe is currently in advanced stage of planning). This limits the power plant efficiency to well under 30% and probably well under 25%. Using the above assumptions and the power plant cost route explained in reference (5) gives the following technical and financial estimates

For a 20 MWe power plant and an optimistic estimate of efficiency of 25% to 30%, probably optimistic even for gasification or steam power plant with reheat –

Biomass at €60/tonne (DEFRA website estimate) 6€c/kWhr Capital charges 6€c/kWhr Operating costs, maintenance and spares 3€c/kWhr

TOTAL (before profit) 15€c/kWhr

The capital charges were derived from €2250/kWe, 7000 operating hours a year and 5.4 years SIMPLE (i.e. excluding interest) payback.

With current base load wholesale electricity prices about 2.2€c/kWhr, a ROC at

4.5€c/kWhr and estimates of the ROC shortfall share-out of around 2.2€c/kWhr, it is no surprise that there are few biomass power plants currently under construction. The difficult-to-estimate recycled payments are a significant proportion of the expected income and are critical to the investment risk. Recycled or share-out payment estimates throughout the project life have to take account of the anticipated commissioning throughout the appraisal period of all new plant eligible for the ROC payments.

Even using longer timescales for capital recovery and more optimistic plant availability data will not significantly change the total number. Recent experience in the UK has provided examples of small-scale novel-technology projects experiencing technical difficulties and thus poor availability, adding yet more difficulties to closing the financing of this sort of project. One possibility of improved economics is combined heat and power production. However sites with a large and steady heat demand are difficult to identify in the UK and at present new combined heat and power developments are rare.

COFIRING Existing power plants have written-down their initial capital costs which removes the 6 €c/kWhr capital charge in the calculation above. They also have considerably lower operations and maintenance costs per kWe through economies of scale. Larger power plants run considerably more efficient steam cycles and achieve fuel to electricity efficiencies above 35%. These combine to produce major environmental and fuel cost advantages compared to smaller power plants. Therefore repeating the above calculation comes up with a number considerably below 15 €c/kWhr. However the provisioning of even a single 350 MWe unit with sufficient biomass for high load factor operation (over 5000 tonnes a day) is impracticable. Cofiring of biomass with coal provides a route for the cost base, efficiency and environmental advantages of a large power plant and can achieve this without impossibly large biomass requirements. Co-firing in pulverised coal fired boilers is not a new idea. Before the requirements for formal procedures, it was common practice to dispose of small quantities of paper, worn-out boiler suits and even damaged banknotes in pulverised coal plants. The material was just introduced via a convenient hole or observation port. The ratio of such material to the coal burn was so low that no environmental or in-plant effects were detectable. Cofiring can improve the overall economics of a coal fired power plant. However the economic benefits of cofiring at low biomass to coal ratios is not sufficient to change the operational regime of the power plant and hence increase coal burn or fossil-fuel derived CO2 emissions. Cofiring in existing power plants removes the problem of interdependence of fuel production and power station permitting/construction/commissioning which is such a difficulty for new biomass plants. One option is to use available wood with minimum pre-processing. The other uses the simpler handling option of wood pellets made from smaller particles of wood. Wood pellets are currently produced in very low volumes in the UK. However wood pellet plants around the world typically have annual production rates of the order of 10,000 tonnes. Annual supply requirements of 100,000 tonnes or so, typical of that for

cofiring our large units, would require sourcing from outside the UK. However if a large and long-term demand for pellets were established in the UK, e.g. through co-firing in existing fossil stations, it is anticipated that funding for UK pellet plants and infrastructure will be forthcoming. Projects initiated with mainly imported pellets could open the market for both UK wood pellets and other UK wood fuels. Fuel supply logistics for biomass power plants have suffered through prolonged periods of precipitation, preventing harvesting of fuel crops, and restrictions on agricultural vehicle movements through foot and mouth factors. A co-fired power plant is less exposed to interruptions in biomass fuel supply than a biomass-only plant as it can return to 100% coal firing. ISSUES IDENTIFIED IN INITIAL STUDY AND ON COMBUSTION TEST FACILITY Tests were carries out at InnogyOne's 0.5 MWt combustion test facility at Didcot using both 100% wood and blends of coal and wood, i.e. cofiring. The wood used was supplied to us in pellet form (figure 1). These were stable and comparatively easily handled when dry. However they expanded and self-heated when wet (figure 2). Figure 1

Wood pellets

Figure 2

Great when dry and not shaken – but…Great when dry and not shaken – but…

Wood Pellets exposed to the weather

The dry pellets were milled back to constituent sawdust particle size (figure 3) before co-firing. Figure 3

Easily milled back to constituent particle sizeEasily milled back to constituent particle size

Ground wood pellets

Some optimisation work was required on fuel handling systems and air to fuel ratios. The carbon monoxide break point for 100% wood firing was at a higher oxygen content than for 100% coal. Stable combustion (figure 4) was achieved without needing to modify the flame detection and associated safety equipment. We were unable to achieve the same thermal input to the burner when burning 100% wood as when burning 100% coal due to limitations of the transport air fan. However otherwise the testing was remarkably trouble-free and no technical issues that would prevent power station trials were identified. Figure 4

Burnt well, alone or with coal in InnogyOne’s 0.5 MWt test facility

Burnt well, alone or with coal in InnogyOne’s 0.5 MWt test facility

Flame from blend of wood and coal(combustion test facility)

For both 100% wood firing and for cofiring, the emissions of SOx, NOx and ash particles were considerably less than for combustion of coal alone. Carbon dioxide and water vapour emissions per unit of heat released were of course slightly higher than for coal-alone combustion. However it must be remembered that the carbon dioxide from the wood component of the fuel is environmentally short-cycle and is regarded as different from long-cycle carbon dioxide from fossil fuel. The nature of wood ash is very different from coal. The calcium oxide and potassium oxide levels are higher and at a level where problems may be expected. Sodium content is variable depending on the wood source. The base over acid ratio for the wood is about 0.9. A value greater than 0.3 in coal is normally an indication that slagging or fouling may occur. However test facility observations with regard to fouling and deposition were encouraging. The ash content of wood is significantly less than coal, resulting in a reduction in ash production. All other things being the same this should lead to an improvement in dust

emissions. However, the stoichiometric air requirements for the same thermal input is 15-20% higher for wood compared to coal, leading to an increase of 2-3% in flue gas flow through the electrostatic precipitators. We believe that this small increase will not significantly increase dust emissions downstream of the precipitators on our power plants. STUDY AND TEST BURN AT TILBURY The fraction of electricity generated by biomass cofired in a coal power plant is eligible for ROCs. Unlike the longer timescales associated with projects for purpose-built biomass plants, this option can be implemented on a relatively short timescale. Utilising existing plant such as boiler and turbine generator limits the amount of capital expenditure necessary to allow co-firing with biomass. Compared with a dedicated biomass plant with capital costs over €2000/kWe, modifications to an existing coal fired station to permit biomass cofiring are considerably less expensive per unit of biomass generation achieved. In the latter case the investment is mainly in biomass storage, handling and burning capability.

Significant co-firing capability (10%) on a large (around 1GWe) coal station requires over 250,000 tonnes of wood pellets a year. The only way we are likely to be able to quickly obtain such quantities of material and transport them to our power plants is to use wood pellets and sea or rail transport. Wood pellets are a premium biomass fuel in terms of ease of handling and transport. However the price of these pellets is high. Over half of the pellet cost can be attributed to the pellet production process which includes milling, drying, compression and extrusion. However, pellets are approximately five times more cost-effective than sawdust for long-distance transport. When transporting large quantities, there are inherent advantages in boat transport. Options available include self discharging ships or the use of existing coal unloading facilities to minimising capital expenditure. The delivered cost of these pellets is considerably greater than coal on an energy basis.

There are three major income streams to finance the high cost of wood pellets; coal replacement costs, £30/MWh buyout and recycled payments. There are additional costs in handling and burning wood pellets over those for coal. There are also minor costs associated with performance impact, manpower and maintenance activities. The draft renewables legislation initially indicated that co-firing would be permissible until March 2011. Our initial calculations suggested that the required capital investment and additional costs for cofiring 10% by thermal input of wood pellets could be covered and still leave us with a net financial gain on the activity. However, the legislation passed by parliament differed from the early draft in stipulating that beyond March 2006, 75% of the biomass fuel must be sourced from energy crops. We do not considered that such fuel will be available by 2006 in sufficient quantities to satisfy the biomass replacement criteria. Therefore our economic evaluation was repeated with the capital cost recovery of co-firing plant expenditure having to be achieved before March 2006. This extremely short operating period, once the construction and planning

and environmental permitting phases are taken into account, results in a target wood pellet price which we were unable to achieve. The anticipated market price for wood pellets will not secure an investment return commensurate with the timescales and risks of co-firing schemes.

The major issues in economic evaluation of co-firing are those covered above. However there are technical issues that we have investigated. The stoichiometric air requirements for the same thermal input is some 15-20% higher for wood when compared to coal. On our power plants, this may give rise to ID fan problems and may limit the amount of wood that can be co-fired on a unit if full load is required. The choice between wood to coal ratio and maximum output would therefore have to be a commercial optimisation, albeit one that would result in maximising wood burn for most of the time. Dry pellets can be stored indefinitely without deterioration. However, if they become wet, they expand to several times their original size and become prone to self-heating. Once the pellets are wet they breakdown and handling is an issue. The bulk density of these wood pellets is 650kg/m3, which compared with 850kg/m3 for coal. This and the lower CV means that a greater volume of material (about 1.8 times) is needed given thermal input. Mechanical handling, dust and fire-prevention issues are major factors in determining the cost of pellet storage, handling and milling facilities.

Many plant operators using wood have experienced fires. Protection against fire, explosion and dust release introduces significant operational costs. An area of particular concern for this study is the choice of pellet milling option. We found that the pellets are relatively easily broken down to the constituent particle size but further breakdown in our mill designs required an impracticable high energy input. The concern is achieving pellet breakdown safely and without interruption or fuel feed route blockages, either in the wood route or in the coal route. We studied and estimated costs for several fuel route options. These ranged from blending wood pellets with coal prior to bunkers (for total co-milling) to dedicated mills for the wood pellets. Mill temperature is an important issue, affecting not only the ignition risk within the mill but also the complete heat balance and coal drying optimisation around the boiler. Inerting of the pellet mill or the blended fuel mills is another option.

Innogy's 3 coal fired power plants have different factors influencing their potential for conversion to cofiring. Tilbury with 3 operational 350 MWe units is the only one of our coal fired power plants with the option of direct fuel delivery by sea. This was the deciding factor in prioritising stations as to their potential for supplying a significant proportion (around 10%) of fuel as biomass. Although imported wood pellets were seen as the only realistic source of most of the fuel for near-term operation at this co-firing ratio we considered that the imported pellets route could open the market for other sources of wood fuel, both pelletized and in a less valuable form requiring processing, either on the power plant site or at other locations.

There are major differences between the fuel milling options available at Innogy's coal fired power plants. Tilbury has spare mill-bays already provided with fuel bunkers. This was another reason for the choice of Tilbury as the lead station for the study. If cofiring with wood pellets at significant wood to coal ratios could not be economically justified at Tilbury then we did not expect any UK power plant to have attractive economics for this sort of investment. The engineering study showed that technically co-firing wood pellets with coal is feasible. Co-firing appears to be viable by either dedicated supply to a single mill or by feeding a blend to all mills. There are some outstanding issues relating to a scheme at Tilbury which are linked to materials handling, pf safety, and fan capacity and possible down rating of a unit (6). Didcot power plant has many technical similarities to Tilbury but access to fuel import routes is via the rail network. Aberthaw is very different in design to Tilbury or Didcot. Its fuel processing routes and combustion chambers were designed for lower volatile coals. The study showed that investment in handling wood pellets from a single ship of sufficient size to give a sensible delivered price for wood pellets was too high for payback before 2006. An additional (but not decisive factor) was the relatively unfavourable tax position that we thought likely for capital investment in biomass co-firing with treatment being less favourable than for energy efficiency investment. We therefore refocused the project on lower capital cost options with lower wood to coal cofiring ratios. We applied for and eventually obtained permission for a test burn of a limited quantity of clean wood. Permission was for 160 tonnes of sawdust from fresh timber, to be burnt at 2 wt% in coal. The difficulties and timescales for obtaining such permission surprised us and reminded us of the risks of time delays for future cofiring plans, delays which could be particularly costly with the 2006 changes limiting the period for capital investment recovery. Our plan was to burn the wood and coal blend during the last few hours before a unit came out-of-service for long-planned major overhaul. This would allow examination of the entire wood route without commercial penalty of unavailability. The test was started. Initial indications from the fuel handling showed that procedures had to be put in place to prevent wood-dust blow at points in the handling cycle (figure 5). This confirmed our cautious approach to the cost estimates for the larger pellet handling facility.

Figure 5

Dust issue when handlingDust issue when handling

The entire power plant (3 units) tripped as soon as the wood cofiring test started. Investigation revealed that the trip was unconnected to wood cofiring, being due to a failure in site compressed air. However the boiler with the necessary permissions for the cofiring test could not be restarted due to the pre-planned major maintenance. We applied for and eventually obtained permission to carry out the wood tests on an adjacent and almost identical boiler at Tilbury. The experience again reminded us of the difficulties and potential problems in permitting cofiring. The 160 tonnes of wood was eventually burnt at 2 wt % in coal and comprehensive data on emissions and plant conditions was obtained. As one would expect from 160 tonnes of wood burnt at 2 wt% concentration, no impact of wood on conditions could be detected. During the initial testing there was a mill fire. The cause was identified as a mechanical fault. However the scale of the fire was greater than expected from this failure (figure 6), probably due to the presence of wood in the mill. This showed the increased risk with this highly reactive material.

Figure 6

Tilbury mill after wood blendTilbury mill after wood blend

THE FUTURE OF COFIRING IN INNOGY?

Environmentally, co-firing wood pellets is beneficial. The low nitrogen and sulphur content of the wood pellets reduce NOx and SO2 emissions. As the release of CO2 from the wood is regarded CO2 neutral, the long-cycle CO2 released to the atmosphere is reduced. The lower ash content of wood/coal blends should reduce dust emissions provided electrostatic precipitator performance is unaffected. The work programme has looked at safety issues including stockpiling, coal and wood dust safety and flame stability. Aspects of different plant impacts have been reviewed including milling, combustion, ash deposition, corrosion and airflow requirements. Technically co-firing wood pellets with coal is feasible. Co-firing is technically possible by either dedicated supply to a single mill or by feeding a blend to all mills. There are some outstanding issues relating to materials handling, fire and explosion safety, and fan capacity and possible down rating of units.

Co-firing schemes using high grade biomass, e.g. woodchips, will only be developed if the biomass suppliers and users (generators) can recover all their capital in a little over 2 years assuming consents and build can be achieved in less than a year. We believe these conditions are too challenging for significant capital investment on cofiring projects.

If the 2006 cofiring constraints were to be removed then significant quantities of biomass co-firing capacity can be established, thus allowing an indigenous high grade biomass supply industry to develop. UK agricultural and forestry sectors have been depressed for some time and are keen to see such opportunities. However with the 2006 limits, Innogy’s interest in cofiring is restricted to low capital cost options with a financial return before March 2006. Our future wood use strategy depends on both wood costs and permitting issues. We have obtained permits for a longer wood cofiring trial at Tilbury burning up to 10,000 tonnes of wood. We expect to be able to extend this trial to 70,000 tonnes of wood at Tilbury. Our wood use beyond this depends on the results of these trials as well as the developing economic situation in ROCs. Technically the issues of cofiring at our Didcot A power plant (4 x 500 MWe units) are similar to those at Tilbury (3 x 350 MWe). Aberthaw (3 x 500 MWe units) is designed for low volatile coal and there are differences in the coal milling and combustion zones. The appropriate wood route even for low cofiring ratios at Aberthaw may be directly to the boiler instead of using a wood coal blend which passes through the mills. The financial analysis shows that dedicated biomass plants are unlikely to be developed unless green tickets (ROCs) soon reach unexpectedly high values or if capital grants to cover a very large proportion of costs are available. Widespread biomass use for power generation in the UK is not expected if significant wind and hydro capacity is added. ALTERNATIVE BIOMASS COFIRING FUELS Wood is not the only biomass fuel available in the UK. We have examined the markets for and carried out tests on various biomass fuels, both vegetable and animal in origin. Some of these are already cofired outside the UK. Many of the fuels examined will come under the waste incineration directive in 2005 and hence can probably be ruled out on economic grounds for long-term fuels. We have considered the issues in burning both animal tallow and meat and bone meal. These products require particular attention because of the potential risks to health. Tallow burnt easily in the 0.5 MWt test facility. Meat and bone meal (MBM) proved more problematic because of the need for prion/protein destruction. Although conventional wisdom suggested a 2 second residence time at 800 Centigrade would be adequate for protein destruction, protein residues were detected after 2 seconds at 1000 Centigrade. 1 second at 1500 Centigrade achieved complete destruction. Potential paths from burners through pulverised coal power plants which may not achieve 1 second at 1500 Centigrade have been identified (figure 7). We have the computational skills and tools to investigate these potential problem routes. However we have not performed condition-specific calculations as we have no plans to use potentially contaminated MBM ourselves.

Observations of the slagging and fouling propensity of MBM showed that although this material is of very different composition to coal ash, slagging and fouling is acceptable up to the cofiring ration then being considered. The major issues in cofiring with these fuels are not technical (apart from the obvious mechanical handling aspects) but public acceptability and obtaining insurance or indemnity against claims, for example from anyone working on or living near a power plant who contracted an illness linked to animal products. Innogy has no plans to cofire material with potential mad Cow (Bovine Spongiform Encephalopathy) links. Figure 7

Possible MBM paths through furnacePossible MBM paths through furnace

MBM

pf sized MBM exits with fly ash

larger MBM sticks to running slag

larger MBM bounces off wall towards hopper

REFERENCES 1. DTI / DEFRA 2002. Renewables Obligation Order. http://www.hmso.gov.uk/si/si2002/20020914.htm 2. OXERA Environmental. 2002 Regional Renewable Energy Assessments. Report to DTI and DTLR. 6 Feb. 3. http://www.mcilvainecompany.com/newsletters/ffnl315/Alstom%20Lands%20Biomass%20Contracts.htm 4. http://pepei.pennnet.com/Articles/Article_Display.cfm?&ARTICLE_ID=166775 5. Hotchkiss, R.C. 2002. Economics, risks and the UK business framework for co-firing and electricity generation. Paper at ETSU/DTI Conference on Cofiring, Nottingham. 6 Feb. 6. Hotchkiss R, Matts D, Myers A, Osborne B, and Riley G. 2002. Biomass – Risks and rewards of cofiring with coal in existing plants and of building new plant. Paper at IMechE Conference on Renewable Bioenergy: Technologies, Risks and Rewards. London 30 Oct. ACKNOWLEDGEMENTS The authors wish to thank their colleagues in InnogyOne at Swindon and on Innogy power stations for their contributions to this work. For part of the work we are grateful to the UG Government Department of Trade and Industry for financial support through the Cleaner Coal Technology R&D programme managed by Mott MacDonald. The project started as one to cofire large quantities of wood but moved to lower capital cost options with lower biomass to coal ratios when changes to cofiring legislation were introduced to limit the use of non purpose-grown wood after 2006.