Experience of Indirect Cofiring of Biomass and Coal

Experience of indirect cofiring of biomass and coal

Rohan Fernando

CCC/64

October 2002

ISBN 92-9029-370-9

Abstract

There has been increasing interest in the use of biomass for power generation in recent years. The principal reason for this is that the use of biomass can significantly reduce net CO2 emissions. Other advantages of utilising biomass are that it diversifies the power plant’s fuel portfolio, it can lead to reductions in SO2 and NOx emissions and that such use can help to dispose of a solid waste. There are some disadvantages of firing biomass which relate to its supply, transportation and composition and these can be reduced if the biomass is cofired with coal. Cofiring can be direct, where the biomass and coal are fired in the same boiler, or indirect, where the combustion or gasification of biomass occurs in a separate unit. This report concentrates on indirect cofiring which is taken to mean technologies in which the ash from the coal and biomass are kept separate. Direct cofiring is relatively straightforward but can lead to several technical concerns. Indirect cofiring incurs greater costs and is particularly suitable for biomass containing troublesome components or when the quality of the ash is of importance. Indirect cofiring is less common than direct cofiring.

The report discusses the relative advantages and disadvantages of direct and indirect cofiring. It then describes the following plants which indirectly cofire biomass: Aabenraa in Denmark, Amergas in the Netherlands, Avedøre 2 in Denmark, Kymijärvi in Finland, Zeltweg in Austria and Västerås in Sweden. Acronyms and abbreviations

BFB bubbling fluidised bed CFB circulating fluidised bed CFBC circulating fluidised bed combustion ESP electrostatic precipitator FBC fluidised bed combustion LHV lower heating value Mtoe million tonnes oil equivalent MWe megawatts electric MWth megawatts thermal pc pulverised coal PF pulverised fuel ppm parts per million ppmw parts per million by weight REF recycled fuel SCR selective catalytic reduction SNCR selective non-catalytic reduction USC ultra-supercritical

2 IEA CLEAN COAL CENTRE Contents

1 Introduction 5

2 Biomass cofiring 7 2.1 Direct cofiring 7 2.2 Indirect cofiring 11 2.3 Advanced biomass reburning 15

3 Indirect cofiring plant 17 3.1 Aabenraa 17 3.2 Amergas 19 3.3 Avedøre 2 21 3.3.1 Multifuel design 21 3.3.2 USC unit 23 3.3.3 Steam turbine 23 3.3.4 Gas turbine plant 25 3.3.5 Biomass plant 25 3.4 Kymijärvi 26 3.4.1 Gasifier 26 3.4.2 Fuels 27 3.4.3 Operating experience 28 3.5 Zeltweg 29 3.5.1 BioCoComb technology 30 3.5.2 Fuels 30 3.5.3 Gasifier 31 3.5.4 Boiler operation 32 3.6 Västerås 33 3.6.1 Biomass boiler 33 3.6.2 Connection with existing plant 34 3.6.3 Water chemistry 34 3.6.4 Feed water pumps and heaters 34 3.6.5 Steam connections 34 3.6.6 Boiler operation 34

4 Conclusions 36

5 References 38

Experience of indirect cofiring of biomass and coal 3 4 IEA CLEAN COAL CENTRE 1 Introduction

There has been increasing interest in the use of biomass for a) The world power generation in recent years. This has been due to nuclear 5% hydro 6% several reasons, the principal one being that the utilisation of biomass can significantly reduce net CO2 emissions. The other advantages of the use of biomass include the fact that it oil 33% diversifies the power plant’s fuel portfolio by adding a biomass 13% potentially less expensive non-fossil fuel. Furthermore biomass firing can reduce NOx and SO2 emissions and it helps to dispose of a solid waste that would otherwise need to be landfilled. However, there are some disadvantages of utilising biomass which relate to its supply, transportation and composition but these can be reduced if the biomass is cofired with coal. Issues which arise when waste, including gas 19% biomass, is cofired with coal have been discussed by coal 24% Davidson (1999). Cofiring can be direct, where the biomass and coal are fired in the same boiler, or indirect, where the Total 386 EJ, 9206 Mtoe combustion or gasification of the biomass occurs in a Population: 5.3 billion separate unit. This report describes indirect cofiring which is taken to mean technologies in which the ash from the coal and biomass are kept separate. b) Industrialised countries nuclear 8%

Typical biomass fuels used for power generation include hydro 6% gas 24% wood-based fuels such as wood chips, sawdust and bark; biomass 3% agricultural wastes such as straw and rice husks; sludges from paper mills and municipal sludges. Though residue fuels can provide an important initial feedstock for the bioenergy industry, large-scale energy production from biomass will need to rely on energy crops such as sugar cane, rapeseed and short rotation forestry. Approximately 13% of world energy demand is met by biomass which is fired at a rate of about 1200 Mtoe (millions tonnes of oil equivalent) per annum as shown in Figure 1. Whereas biomass is the largest energy source (33%) in developing countries, it oil 36% coal 23% represents only 3% of energy consumption in industrialised countries. In the United States 4% of primary energy is Total 257 EJ, 6131 Mtoe (67%) produced by biomass whereas the corresponding figures in Population: 1.3 billion (25%) Finland and Sweden are 21% and 17% as the latter two countries have large forest-based pulp and paper industries (Swanekamp, 1995; Engström, 2000). The European c) Developing countries Parliament has set targets for Member States that biofuels hydro 6% nuclear 1% should account for 2% of fuels sold by December 2005 and gas 8% 5.75% by 2010 (Cordis Focus, 2002). biomass 33% The drawbacks to using biomass for power generation include the fact that in many countries the supply of biomass is widely dispersed and there may not be an established infrastructure for harvesting and transporting it to the power plant. The seasonal nature of biomass raises further oil 25% complications. It is readily available during harvesting but scarce during cultivation and growth. The composition of biomass is very different from coal as shown in Table 1 which compares hard coal and brown coal with several coal 27% biofuels. Biomass can contain much higher moisture levels, up to 50%, which can adversely affect combustion by Total 129 EJ, 3074 Mtoe (33%) absorbing heat during evaporation. Its heating value is also Population: 4.0 billion (75%) significantly lower than coal. Moreover, its bulk density is much less than coal hence a greater quantity of fuel needs to Figure 1 Primary energy consumption (1990) be collected, handled, transported and stored. The costs (Engström, 2000)

Experience of indirect cofiring of biomass and coal 5 Introduction

Table 1 Fuel analysis of coals and selected supplementary fuels (Hein and Scheurer, 2000)

dried sewage hard coal brown coal wood straw RDF sludge LHV, raw, MJ/kg 28 9 12.4 15 23.5 10.6

moisture, raw, % 5.1 50.4 33 10.6 4.1 3

volatile matter, dry, % 34.7 52.1 83.2 74.4 82.6 49.5

ash, dry, % 8.3 5.1 0.34 6.1 12.2 45.1

Fixed C, dry, % 57.1 42.8 16.5 19.9 5.2 2.4

C, dry, % 72.5 65.9 48.7 47.4 56.8 25.0

H, dry, % 5.6 4.9 5.7 4.5 7.9 4.9

N, dry, % 1.3 0.69 0.13 0.4-0.78 0.74 3.2

S, dry, % 0.94 0.39 0.05 0.05-0.11 0.25 1.1

Cl, dry, % 0.13 <0.1 <0.1 0.4-0.73 0.82 <0.1

O, dry, % 11.1 23 45 40.4 21.3 17.7

ash fusion temperature, °C 1250 1050 1200 850 1120 1200

associated with these activities mean that large biomass power plants (>300 MWe) are impractical. The smaller plant size and the lower fuel heat contents result in biomass plant being inefficient compared with coal-fired plant. Existing biomass fired plant in the USA have heat rates in the range 14–21 MJ/kWh compared to 9.5–14 MJ/kWh for coal-fired plant. However, if the biomass cost is very low, the efficiency may not be a key economic criterion. Other technical issues can also arise. For example, the use of some biofuels such as switchgrass can lead to increased slagging and fouling on boiler surfaces. Biofuels containing high chlorine levels such as straw can cause corrosion. Fly ash resulting from biomass firing does not always meet the requisite standards and this can reduce fly ash marketability (Paul and Maronde, 2001).

This report describes the indirect cofiring of biomass and coal in hybrid plant. Indirect cofiring is much less common than direct cofiring. The plants which are described are: ● Aabenraa in Denmark; ● Amergas in the Netherlands; ● Avedøre 2 in Denmark; ● Kymijärvi in Finland; ● Zeltweg in Austria; ● Västerås in Sweden.

For each of these, the design of the plant is described. What modifications were needed to allow the plant to fire biomass are discussed. The types of biomass fired and the operational issues that have arisen during biomass firing are included. Though the report concentrates on indirect cofiring technologies, the relative advantages and disadvantages of direct and indirect cofiring will first be considered.

6 IEA CLEAN COAL CENTRE 2 Biomass cofiring

Cofiring biomass with coal has the potential to overcome around 50 $/kW for cyclone or fluidised bed boilers that some of the drawbacks of firing pure biomass. Cofiring does cofire up to 10% biomass. Additional costs may be incurred not involve the high capital costs of building a new biomass if the biomass contains high levels of alkaline earth metals or plant but the significantly lower retrofitting costs for an chlorine. These elements can react with the volatile matter in existing plant. Retrofitted boilers can fire biomass when the coal and SO2 during combustion to form fine particulates biomass supplies are plentiful but switch back to coal when which deposit on boiler tubes. Additional design biomass supplies are low. Cofiring increases the efficiency of modifications such as increased waterwall surface area, energy conversion by firing the fuel in a larger plant combustion air control and additional sootblowing may be compared to a smaller one firing pure biomass. Cofiring needed to mitigate these effects. The total capital costs of enables the coal-fired plant to reduce its SO2 emissions as retrofitting an existing pc boiler to cofire biomass are in the biofuels generally contain less sulphur than coal. Biofuels range 50–350 $/kW or exceptionally as high as 700 $/kW. also tend to contain low nitrogen contents which leads to low The capital costs of the retrofit should be offset by the NOx emissions. Furthermore biofuels contain higher volatile differential fuel cost of biomass and possible tax incentives. matter contents than coal which tend to form less NOx in The cost of biomass fuel in the USA ranges from 0 $/GJ to low-NOx burners. about 1.30 $/GJ. Obtaining the fuel at zero cost would require the power plant to be located adjacent to the fuel 2.1 Direct cofiring source. Agricultural residues cost about 0.95 $/GJ delivered to the plant. Forest residues cost more (2.3–3.3 $/GJ) due to Direct cofiring involves firing the coal and biomass in the the additional costs of obtaining and transporting the same boiler. This is the simplest and most widely applied material from remote locations. Current coal costs are technology for cofiring biomass. As all the components of typically in the range 1.1–1.3 $/GJ and EPRI studies suggest the biomass enter the coal boiler several technical issues that for cofiring to be economic, the biomass must be arise which are discussed below. Retrofitting a coal-fired delivered at a price 0.24–0.38 $/GJ below the price of coal boiler to cofire biomass requires modifications to the fuel (Paul and Maronde, 2001; Laux and others, 2000). A survey handling, storage and feed systems. The biomass can be fed of biomass fuel prices in 20 European countries showed that to the boiler as a separate fuel or blended with coal. Cofiring the price varied from the cheapest, which was waste wood at less than 2–3% biomass on a thermal basis may be possible 1 A/GJ, to the most expensive which was refined biomass using existing pulverisers by previously blending the fuels. pellets at 8.4 A/GJ (VTT Energy, 2001). In the UK some Cofiring greater than this amount of biomass will require a biomass fuels such as MBM (meat and bone meal) and separate feed system to act in parallel with the coal feed tallow could have negative costs (Canning, 2002). system. The blended-feed system incurs lower capital costs but the separate-feed system has the advantage of the The major technical areas of concern when cofiring biomass individual control of biomass and coal feed rates. Experience directly with coal in pc boilers are (Hein and Scheurer, on pc-fired boilers shows that blending biofuels with coal in 2000): the fuel pile can significantly impact pulveriser performance. ● If the proportion of biomass is high, for example 10% of Blending small quantity of sawdust with coal reduces thermal throughput, the total fuel volume will almost pulveriser capacity due to changes in fuel moisture and double and this will prevent combined grinding and Hardgrove Grindability Index. Unless there is significant feeding. In addition biofuels with low melting points can excess mill and drying capacity, such blending may result in lead to caking in the mills and ducts. significant capacity derating of the boilers. Tests and ● The lower melting points of some cofired ashes can calculations have shown that when 7–10% of the thermal increase the likelihood of slagging and fouling on the input is from biomass, there is a drop in overall boiler walls of the combustion chamber and the boiler tubes. efficiency of 0.3–1.0%. Separate injection is useful for ● Some biofuels, such as straw, which contain high biofuels with low bulk densities which are not readily chlorine levels can lead to high temperature corrosion. blended with coal (Laux and others, 2000; Paul and The superheater surfaces are most affected due to their Maronde, 2001). Cyclone boilers are particularly suited for high steam temperatures. Any efforts to increase firing biomass. The burners for these are large horizontally efficiency by raising steam temperatures will aggravate oriented cyclone barrels where the fuel, which is crushed this effect. rather than pulverised, burns out in the slag layer on the ● The possibility of fouling of convective heating surfaces walls of the barrel. Because they are tolerant of larger sized is greater for fuels with low ash melting points. Cofiring fuel particles, cyclone boilers do not share the 2% limit on sewage sludges can increase erosion due to their high cofiring which applies to most pc plant. In a cyclone boiler a ash contents but this will not be a problem for biofuels 10% thermal input from biomass is possible using the lower- with low ash contents. cost blended fuel feeding system (Hughes, 2000). ● Cofiring can affect SCR catalysts which are upstream of the precipitators in the high dust configuration. Fly ash The capital costs for blended feed systems are in the range containing alkali metals, arsenic, phosphorous or 10–25 $/kW, compared to 165–200 $/kW for the separate fluorine can deactivate the catalyst. feed system. The retrofit costs are estimated to be lower at ● The constituents of the ashes will change during cofiring

Experience of indirect cofiring of biomass and coal 7 Biomass cofiring

and this will affect the ash utilisation and disposal been commonly utilised for co-combustion of biofuels and options. The ash composition of biofuels is coal particularly in Scandinavia. This is due to the high fundamentally different to that of coal. The alkalinity of degree of fuel flexibility of the technology in relation to the ash is very much higher with typical base/acid ratios particle size, density, moisture and ash contents of the fuel. exceeding 1 and sometimes 2 whereas for coal the ratio The bed material circulation and high turbulence in the is typically about 0.5. Furthermore the alkalis in combustion chamber ensures good mixing of fuel and biomass ash are more available and reactive than those combustion air. This facilitates the combustion of biofuels in coal (Tillman, 2000). There are other factors which with high volatile contents and additionally enables efficient may limit the use of cofired ash as a cement or concrete heat transfer in the boiler. The high heat capacity of the bed additive. Firstly the ash could have a high carbon material allows the use of fuels with high moisture contents content as the biofuel may be relatively wet with such as biomass. CFB boilers are very flexible for changes in typically a large particle size. Secondly some fuel quality and it is possible to change rapidly from coal to constituents from fly ash originating from herbaceous biomass in the boiler and vice versa. When firing biomass fuels such as straw may negatively influence concrete the process of receiving, handling, pre-processing, storage, strength (ENERGIE, 2000). conditioning, blending, conveying and feeding the fuel to the ● The lower sulphur contents of most biofuels will boiler will require space and equipment designed specifically decrease the load on the FGD plant. However, the for the feedstock. Though FBC technology is very flexible, if presence of HCl in the flue gas will impair the operation the feeding characteristics of the secondary fuel vary too of the FGD plant. An increased presence of heavy much for the primary fuel, a separate feeder may be needed. metals such as mercury, arsenic or lead in the flue gas Other problems that may occur when firing biomass in FBC could be concentrated in the FGD residues. boilers are related to modified vertical temperature profile, ● The presence of volatile heavy metals such as mercury slagging and fouling on boiler walls when firing fuels with in the biofuel will lead to increased emissions from the high alkaline contents, bed agglomeration when firing fuels stack. with high alkaline and aluminium contents and chloride corrosion on heat transfer surfaces. These possibilities are illustrated in Figure 2. There are approximately 150 fluidised bed boilers installed Fluidised bed combustion (FBC) either in bubbling fluidised in Scandinavia ranging from 20 MWth in sawmills to bed (BFB) or circulating fluidised bed (CFB) boilers has 310 MWth in the pulp and paper industries. Secondary fuels such as sawdust, wood chips, forest residues are cofired with main fuels such as peat, wood, bark or coal. The widespread use of FBC technology is not surprising in sparsely populated Finland where mass burning facilities for wastes are not economically feasible and large quantities of biomass 10 are available. In Sweden, biomass is cofired with fossil fuels 5 in grate boilers, BFB, CFB and PF boilers for heat and 4 power generation. Grate boilers usually supply district air pre-heater 6 8 heating. FBC boilers are used in the paper and pulp 3 ESP FGD industries. Several PF boilers originally firing coal have been 2 modified to cofire biomass. The taxation system in Sweden 1 encourages the use of biomass. In the Netherlands and in Germany, biomass wastes such as sewage sludge and 7 9 demolition wood are cofired at relatively small percentages in some coal-fired plant. In Austria biomass cofiring takes 1 mill: wear, capacity place mainly in the pulp and paper industries using their own residues in small industrial boilers and in two large 2 combustion chamber: slagging, fouling demonstrations at St Andrä and Zeltweg plants.The major 3 superheater: fouling, corrosion technical issues which need to be addressed when cofiring 4 conv. heat exchangers: fouling, errosion biomass with coal in different types of boilers relate to feedstock processing, combustion, flue gas cleanup and 5 DeNOx-catalyst: deactivation, capacity, errosion byproduct utilisation and these are summarised in Tables 2 6 ESP: dust composition, capacity to 5 (ENERGIE, 2000). The European Bioenergy network 7 Ash: Use/disposal has evaluated 21 biomass cofiring plants in Finland, Sweden, Denmark, Germany, Italy, Austria and Portugal. These plants 8 FGD: capacity cofire biomass with coal, peat and waste. In nine plants 9 FGD: use of by-products biomass was cofired with coal. The contribution of biomass 10 stack: emissions in grate-fired boilers ranged from 20–95%, in fluidised bed boilers from 22–90%, in pulverised plants from 3–20% and in gasifier plants from 3–8% of total plant fuel consumption. Figure 2 Areas of concern in co-combustion (Hein The size of these plants ranged from <1 to 300 MWth. They and Scheurer, 2000) found that the main problems in cofiring and gasification related to fuel handling and feeding. Most combustion

8 IEA CLEAN COAL CENTRE Biomass cofiring

Table 2 Cofiring technical constraints relating to biomass pre-processing (ENERGIE, 2000)

Technical constraint Solution

Pre-processing of biomass – No equipment and space at the power plant for pre- – Buy specified biomass from certified suppliers processing

Receiving and handling of biomass – Emissions of dust, methane and odours – Receive the fuel indoors with an increase of air exchange – Protect workers and take precautions against fires and explosions

Fuel Quality Assurance – Determination and surveillance of the quality of the received – Use standardised, certified and regularly analysed biomass biofuels – Undertake visual inspection and regular sampling and testing in independent laboratories – Install screening equipment to control size distribution

Storage – Problems with bridging, risk of fires and dust or methane – Compress bulk biomass into pellets or briquettes induced explosions in the silos – Install prevention equipment

Conditioning –- Increased wear of shredder and mills – Use a stone or sand remover or trap and a metal –- Risk of spark ignition, explosion and fire separation system – Install a security system with spark detection and water or nitrogen fire protection

Conveying – Problems of bridging, blockages, stickiness and back – Mix fresh biomass with dried biomass slipping of frozen biomass – Screen to exclude oversized material – Use proved belt and vertical conveyor systems – Cover conveyor belts – Avoid long transport distances and junctions

Feeding – Tightness or blocking of the feeders – Use reliable feeder systems – Install more than one feeder point – Locate optimum feeding point – Adjust feeding rates

technologies functioned satisfactorily but it was difficult to could cofire wood in the range 2–10%. The key factors homogenise the biomass fuels suitable for combustion. Fuels affecting combustion efficiency have been shown to be with high alkali content were problematical and the use of particle size, particle dryness and fuel chemistry. The tests different biomass fuels with coal required additional control also showed that the loss in boiler efficiency during and advanced handling technologies (Järvinen and cofiring was small in the range 0.3–0.6% and was due to Alakangas, 2001). Current technologies for co-gasifying the moisture in the fuel. In 2000 there were six plants in the waste and biomass with coal have been critically assessed by USA cofiring coal and wood residue products on a Ricketts and others (2002). commercial basis and at least six were planning tests. The practical feasibility of such projects depends very much on In the USA since the 1980s, several cofiring trials have the price of biomass relative to coal and the availability of been successfully completed in a range of boiler types biomass within 80 or 160 km of the plant (Costello, 1999; (cyclones, pc, stokers, BFB and CFB) in plant having Baxter, 2000). The Western Regional Biomass Energy capacities ranging from 15 to 500 MWe. These plants Program has initiated a study to examine the feasibility of which have or intend to cofire are listed in Table 6. The integrating a gasifier with an existing coal-fired boiler and results of these demonstrations have shown that cyclone replacing 15% of the coal with gas produced primarily boilers are particularly suitable for cofiring biomass as they from waste wood. The project will consider the require minimal modifications for the reasons discussed implementation of the proposal at the Sheldon Station, a above. Cyclone boilers can cofire wood in the range 1–10% 225 MW power plant near Hallam, Nebraska, USA by thermal input and possibly as high as 15%. PC boilers (Modern Power Systems, 2002a).

Experience of indirect cofiring of biomass and coal 9 Biomass cofiring

Table 3 Cofiring technical constraints relating to combustion system (ENERGIE, 2000)

Technical constraint Solution

Boiler design – Increase is manageable in existing boiler if biomass – Increased gas volumes and water content in gas proportion is small (5–10%)

Boiler and burner behaviour – Melted metals on grate – Special coatings with protection and deflection materials – High temperature chlorine induced boiler corrosion – Add more feeding points to ensure good biofuel distribution – Sintering in boiler due to hot spots in freeboard – Change circulation patterns and increase central velocity – Increased risk of slagging and fouling – Increased soot blowing – Increased risk of erosion and deposits at the burner – Adjust maintenance requirements

Burnout problems – In CFBC: significant freeboard combustion and final – Reduce share of fine material combustion of fines and unburned gases in hot cyclone – High temperature before superheater due to content of fine material

High temperature corrosion – Increased condensation, corrosion and deposits on – Special protection coatings superheater, economiser and air preheater – Use austenitic and martensitic steels instead of ferritic steel – Reduction of superheated steam production due to lower – Installation of steam heated air pre-heater CFB bed temperature – Sonic blowers to remove slag deposits

Table 4 Cofiring technical constraints relating to flue gas clean-up (ENERGIE, 2000)

Technical constraint Solution

Flue gas path – Increased flue gas volumes and temperatures – Substitute lignite with coal

Catalysts – Accelerated ageing and deactivation of SCR catalysts – Use biofuel with lower alkali content – Regenerate the catalyst – Use special catalysts – Remove catalyst poisons from flue gas

Flue gas desulphurisation – Control of limestone addition more difficult due to greater – Purchase more homogeneous biomass variation in ash composition of biomass wastes – Install more advanced FGD systems

Heavy metals – Use smaller amounts of biofuels – Emission limits may be exceeded – Install additional flue gas cleaning

Table 5 Cofiring technical constraints relating to by-product disposal (ENERGIE, 2000)

Technical constraint Solution

Ashes – Increased bottom ash and fly ash volumes – Modify ash handling systems

Composition and quality of ash and gypsum – Adjust type and amount of biomass to ensure variation in – Modified ash properties ash properties are within coal ash range – Limit amount of biomass – Reduce alkaline and chlorine content of biomass – Use indirect cofiring system to keep ashes separate – Increase air supply for burners or biomass particle residence times – regular use of soot blowers

10 IEA CLEAN COAL CENTRE Biomass cofiring

Table 6 US biomass cofiring plants (Costello, 1999)

Utility Plant Boiler Type

In commercial operation

Northern States Power Allen S King cyclone

NYSEG Greenidge pc

NYSEG Hickling stoker

NYSEG Jennison stoker

Southern Company Yates pc

Tacoma Public Utilities Steam Plant 2 fbc

TVA Colbert pc

Tests conducted

Georgia Power Plant Hammond pc

Georgia Power Plant Yates pc

GPU Shawville pc

GPU Seward pc

Madison Gas and Electric Blount Street pc

NIPSCO Michigan City cyclone

Santee Cooper Jeffries pc

Savannah Electric Plant Kraft pc

TVA Kingston Fossil pc

TVA Allen Fossil cyclone

Tests planned

GPU Seward pc

IES Utilities Ottumwa pc

IES Utilities 6th Street pc

Niagara Mohawk Dunkirk pc

NIPSCO Bailly cyclone

Southern Companies Gadsden pc

2.2 Indirect cofiring very much higher than for direct firing. Indirect cofiring is most suitable for biofuels containing relatively difficult Indirect or hybrid cofiring as it is sometimes called involves components or when it is particularly important to prevent either pre-gasifiying the biofuel in a separate unit or firing the coal ash from being contaminated. Indirect cofiring the biofuel in a separate combustor and routing the steam usually involves upstream gasification, upstream pyrolysis or produced to the main turbine where it is upgraded to higher separate combustion with steam-side integration. There is conditions. This latter process is also known a parallel firing. another technology known as upstream hydro thermal Indirect cofiring is less commonly found than direct cofiring. upgrading which is still under development. These It has the major advantages that the coal ash is not technologies have been compared by Van Ree and others contaminated by any constituent of the biofuel and that these (2001). constituents cannot cause corrosion or slagging in the main plant. Furthermore the total biofuel capacity is not limited by Upstream gasification involves gasifying the biofuel existing constraints imposed by installed hardware and any upstream of the coal-fired boiler. The fuel gas which is problems with the biomass plant will not result in the whole produced is fired in specific low calorific (bio)gas burners. power plant being shut down. However, the major There are two main approaches to this technology, namely disadvantage of indirect firing is that installation costs are the concept offered by Lurgi (Germany) and that offered by

Experience of indirect cofiring of biomass and coal 11 Biomass cofiring

Foster Wheeler (Finland). In the Lurgi concept, the biofuel is In the upstream Hydro Thermal Upgrading (HTU) process a gasified in a CFB gasifier at atmospheric pressure and about wet biofuel is converted to a biocrude at high pressure 850ºC. The fuel is pre-treated by size reduction and drying to (12–18 MPa) and temperature (300–350ºC). This biocrude meet the gasifier specification of particle size in the mm which has similar characteristics to a pyrolysis oil is cofired range and moisture content of <20%. After gasifying, the in specific burners in the coal boiler. A potential advantage raw fuel gas is cleaned at low temperatures by a scrubber of this process is that it is able to process wet biofuels such and baghouse after which the fuel is fired in low calorific gas as sewage sludge and pig manure without predrying but this burners in the coal boiler. The main advantage of this process is still under development and is not commercially concept is that more of the contaminants in the fuel are available. removed before entering the coal boiler and hence a variety of fuels can be used without causing serious problems Van Ree and others (2001) have also conducted a feasibility regarding emission constrains or ash quality. An example of study of the different indirect cofiring concepts in the Dutch this type is the Amergas plant in the Netherlands which is context by comparing a base case pc plant with a described in more detail in Chapter 3. representative plant for each type of indirect cofiring. For the base case they chose a 600 MWe plant with net electrical An alternative gasification concept is the Foster Wheeler Oy plant efficiency of 40% (LHV) which operates for 6000 h/y. (Finland) approach in which the biofuel is still gasified in an The following cofiring technologies were considered: atmospheric pressure CFB gasifier. The fuel specification is ● direct cofiring (same feed); less stringent in that the maximum moisture content has to ● direct cofiring (separate feed); be less than 60%. Hence in most cases fuel drying is not ● indirect cofiring – gasification, Lurgi; required thus reducing costs. The fuel gas is fired in the ● indirect cofiring – gasification, Foster Wheeler; boiler using very low calorific gas burners without additional ● indirect cofiring – separate combustion with steam-side gas clean-up, thus further reducing costs. This design has the integration; advantage of high overall conversion efficiency of the biofuel ● indirect cofiring – slow pyrolysis; to produce power but as a greater proportion of the biofuel’s ● indirect cofiring – fast pyrolysis; contaminants reach the coal boiler, the range of fuels that ● indirect cofiring – HTU. can be used will be limited to prevent potential problems with slagging/fouling, emission constraints and ash quality. For each of these technologies steady-state thermodynamic An example of this concept can be found at the Kymijärvi calculations were performed giving overall mass and energy plant in Finland. A variation of this gasification concept has balances and net overall electrical conversion efficiency for also been used by the Verbund Group in Austria at the the substitute fuel. They considered both a 10% and 40% Zeltweg plant. In this system the biofuel is pyrolysed substitution of coal by biomass. Using literature information upstream of the coal-fired plant. Both plants are described in and data provided by technology suppliers they calculated Chapter 3. There are three types of pyrolysis processes, the additional investment costs for each of the cofiring namely, slow, fast and flash pyrolysis. Slow and fast concepts and these are given in Table 7. The results showed pyrolysis, producing respectively char and oil as the main that direct cofiring with the same feed was by far the products, have been identified as the most suitable processes cheapest technology. All the indirect firing technologies were for indirect cofiring. In the case of slow pyrolysis, the size at least ten times more expensive but of these the Foster reduced and dried biofuel is pyrolysed at relatively mild Wheeler gasification technology was the least expensive. conditions of atmospheric pressure and 450ºC. The char produced is mixed and combusted with the coal. Part of the They also considered other constraints on cofiring. In gas produced is used to drive the pyrolysis process and the addition to technical constraints there are those imposed by remainder is fired in dedicated gas burners in the coal boiler. authorities and financial and legal considerations. Focusing Depending on the fuel a low temperature gas clean-up on the technical limitations, the potential for partial system may be part of the system. Fast pyrolysis involves replacement of the coal depended strongly on the quality of pyrolysing the size reduced and dried biofuel at 15 kPa and the biomass and the effect on the nominal load of the plant. 500ºC to produce about 70% oil, 15% char and 15% gas. Some examples of the technical limitations included: The gas drives the pyrolysis process and both the oil and the ● Grindability of the coal/biomass blend. As most biomass char are fired in the coal boiler. As most of the contaminants is soft or fibrous whereas coal is hard, the pulverisation in the oil are concentrated in the oil and char, fast pyrolysis of the blend using existing pulverisers may be limited. is only applicable for relatively clean biofuels. ● Capacity of unit components. As biomass has a higher moisture content, the flue gas flowrate is increased and Another system for indirect cofiring is to fire the biofuel in could exceed the capacity of fans, air heaters and flue an entirely separate combustion system and the heat gas clean-up systems in existing units. produced is fed to the steam boiler of the coal-fired power ● Severe slagging and fouling. The ash melting plant and used for relatively high efficiency power temperatures of some biofuels may be low due to high generation. An advantage of this system is that the biofuel is alkali metal, calcium and iron contents. This can lead to fired without significantly affecting the coal combustion slagging and the high sodium and potassium levels can process. Examples of this application are the 95 MWth straw lead to fouling. and wood-fired boiler at Aabenraa and the 100 MWth straw ● Corrosion of furnace walls and superheaters due to high and wood-fired boiler at Avedøre plants in Denmark. These chlorine levels. plants are described in detail in Chapter 3. ● Erosion due to high ash contents.

12 IEA CLEAN COAL CENTRE Biomass cofiring

Table 7 Cofiring predictions for base case coal-fired power plant (Van Ree and others, 2001)

Net electrical efficiency with Specific additional Concept substitute fuel (%LHV) investment cost (e/kWe)

Co-combustion percentage (energetic base) 10 40 10 40

Direct co-combustion 39.5 39.5 40 25

Separate size red., drying, feeding, combustion 38 38 500 285

Upstream gasification (Lurgi) 35.5 35.5 1120 735

Upstream gasification (FW) 38 38 455 300

Upstream slow pyrolysis 32.5 32.5 1240 1240

Upstream fast pyrolysis 36 36 935 935

Upstream HTU 35.5 35.5 620 490

Upstream separate combustion with steam-side integration 38.5 38.5 940 575

Other technical aspects that should be considered when from contaminated fuels such as demolition wood and sewage maximising the proportion of biomass are the operating sludge would exceed limits (Van Ree and others, 2001). flexibility, the maximum load and unavailability. These factors are especially important in current liberalised Another theoretical investigation of parallel combustion of markets. biomass and a comparison with other modes of firing has been performed by STORK (Van der Wal,1999) and reported In addition to the technical limitations, there may be by van Zanten (2000). Parallel combustion involves firing environmental limitations. Special attention needs to be paid biomass in a separate boiler which is then integrated into the to the quality of fly ash and bottom ash. In the Netherlands, steam circuit of a large coal-fired plant. The coal-fired boiler fly ash from the combustion of biomass and coal containing heats the steam from the biomass boiler to higher less than 10% biomass is regarded as fly ash from coal. The temperatures resulting in higher efficiencies for electricity status of fly ash from firing fuels containing more than 10% generation. Utilisation of other equipment from the coal-fired biomass is not clear. Some European and domestic legislation plant also contributes to higher overall efficiencies. An is not precise as to the status of some byproducts. The advantage of separate biomass combustion is that there is no legislation constraining NOx, SO2, dust and heavy metal possibility of corrosion, fouling or ash contamination of the emissions is currently subject to revision. An analysis of how coal-fired plant. Indeed as parallel combustion affects only European regulations affect solid residues from cofiring the steam cycle of the existing plant, the availability and suggest that residues from clean fuels such as waste wood reliability of the existing plant are unaffected by any and straw would not exceed emission limits whereas residues problems with the biomass boiler.

medium pressure steam to steam turbine steam from fluidised bed boiler medium pressure steam from steam turbine high pressure steam to steam turbine

super heater reheater

convective super heater

evaporator economiser boiler feedwater

water to fluidised bed boiler

Figure 3 Schematic integration of steam integration at parallel combustion (Van der Wal, 1999)

Experience of indirect cofiring of biomass and coal 13 Biomass cofiring

In the STORK study a conventional coal-fired plant of parallel combustion is highly dependent on the efficiency of output 600 MWe with a net electrical efficiency of 41.7% the coal-fired plant. If, for example, a supercritical coal-fired was taken as the reference station. The biomass plant was a boiler is used for integration, the efficiency of the biomass fluidised bed boiler producing 49 MWth. The biomass steam conversion will increase proportionately. Parallel gasification was integrated with the steam system of the coal fired plant and direct cofiring have the advantage that the flue gas from before the superheater as shown in Figure 3. The generating the biomass is diluted with that from the existing plant. If capacity of the station integration was assumed to remain at there are any contaminants in the biomass in parallel 600 MWe. Hence after integration the coal consumption combustion, as the flue gas is separate, additional clean-up would decrease. All additional losses compared to the base will be needed. case were attributed to the biomass conversion. For the purposes of the calculation it was assumed that the The total investment costs for the different biomass remaining coal consumption produced electricity at the same conversion technologies have been estimated for a biomass efficiency prior to conversion. plant producing 20 MWe. The estimates were made by STORK based on existing projects or on in-house The following technologies were compared: information and these are given in Table 9. Based on these ● Parallel combustion of biomass and integration with a investment costs, cost projections for the annual running coal-fired boiler. costs and the electricity costs have been made and these ● Direct cofiring of biomass in a coal-fired boiler. figures are contained in Table 10. For the latter calculations ● Gasification of biomass and gas combustion in a coal- the following assumptions were made: fired boiler (parallel gasification). ● cost of capital – interest of 10.3%; ● Stand-alone combustion of biomass. ● cost of biomass – zero; ● Stand-alone gasification of biomass. ● operational cost – 0.36 million A/y; ● maintenance cost – 2.5% of investment cost/year; A thermodynamic evaluation of the different technologies ● overhead cost – 40% of operation and maintenance cost; produced the following electrical efficiencies for biomass ● coal cost – 50 A/t; conversion (Table 8). The study found that the availability ● cost of O&M and depreciation of existing plant – and reliability of fluidised bed combustors were higher than 0.018 A/kWh; for gasifiers as combustion was a more established ● hours of operation – 7500h. technology. Fuel flexibility is a further advantage of parallel combustion. The separate boiler is able to combust a variety Direct cofiring clearly incurs the lowest costs. Parallel of biofuels. Fluidised bed boilers, in particular, are combustion and parallel gasification have similar costs and characterised by a high degree of fuel flexibility and the high are more expensive than direct cofiring but have advantages heat transfer in the bed material resulting in controlled and which have been discussed above. The stand-alone stable combustion. The efficiency which can be attained with technologies are the most expensive. The costs per kWe in the STORK study are greater than those in Table 7 as STORK assessed a much smaller plant. Although the figures contained in Table 10 are based on a zero biomass cost, the Table 8 Thermodynamic evaluations of biomass cost of electricity of increasing the biomass cost has also conversion technology electrical been calculated and represented in Figure 4. These results efficiencies (Van der Wal, 1999) show that, as the biomass costs increase, the production costs Parallel combustion 40% per kWh will increase faster for technologies with lower efficiency and the gradient for cost is steepest for stand alone Parallel gasification 36% combustion and least for parallel combustion. The main Direct co-firing 37.5% advantages of parallel combustion were considered to be (Van der Wal, 1999): Stand-alone gasification 38% ● high electrical efficiency (higher than direct cofiring and Stand-alone combustion 26% parallel gasification);

Table 9 Capital and operating costs for a 20 MWe biomass plant (Van der Wal, 1999)

Specific Total cost, Annual cost, Electricity cost, Installation type investment, e/kWe million e million e/y e/kWh

Parallel combustion 1360 27 1.8 0.030

Parallel gasification 1270 25 1.7 0.029

Direct co-firing 680 14 0.45 0.021

Stand-alone combustion (FBC) 1890 38 5.8 0.039

Stand-alone gasification (IGCC) 2950 59 8.7 0.058

14 IEA CLEAN COAL CENTRE Biomass cofiring

Table 10 Cost projections for a 20 MWe biomass plant (Van der Wal, 1999)

Stand-alone Stand-alone Parallel Parallel Direct co-firing combustion gasification combustion gasification

Capital charge, million e/y 3.9 6.1 2.8 2.7 1.9

Operation and maintenance

Personnel 0.36 0.36 0.36 0.36 0.36

Maintenance 0.95 1.5 0.68 0.68 0.36

Overhead 0.54 0.73 0.41 0.41 0.27

Sub-total, million e/y 1.9 2.6 1.5 1.5 1.0

Fuel costs

wood 0.0 0.0 0.0 0.0 0.0

avoided coal 0.0 0.0 -2.5 -2.5 -2.5

Sub-total, million e/y 0.0 0.0 -2.5 -2.5 -2.5

Sub-total, million e/y 5.8 8.7 1.8 1.7 0.45

kWh cost excluding coal plant 0.039 0.058 0.012 0.011 0.003

kWh cost coal plant 0.0 0.0 0.018 0.018 0.018

Total kWh cost, e/kWh 0.039 0.058 0.030 0.029 0.021

0.16 Biomass combustion Biomass gasification 0.14 Parallel combustion with coal 0.12 _ _ Parallel gasification with coal 0.1 Direct co-firing with coal

0.08

0.06

Electricity cost, C/kWh 0.04

0.02

0 9.1 18.2 27.2 36.3 45.4 54.5 63.5 72.6 81.7 90.8

_ Biomass cost, C/t_

Figure 4 Sensitivity of biomass cost on the electricity production cost (Van der Wal, 1999)

● low investments cost (lower than stand alone the heat input, at a point above the primary combustion zone technologies and equal to parallel gasification); to create a reducing region in which the NO produced in the ● fuel flexibility; primary zone is reduced to nitrogen. The main technical ● uses existing technologies; issues regarding reburn have been discussed by Soud and ● no mixing of ash products; Fukasawa (1996). The most widely used reburn fuel in ● minor influence on existing plant. utilities has been natural gas though coal, oil and orimulsion have also been used. Biomass could also be used as a reburn 2.3 Advanced biomass reburning fuel. It is renewable, low in sulphur and cheap, and pilot- scale tests have shown that it can outperform other fuels in Another type of indirect cofiring is advanced biomass providing NOx reductions (Zamansky and others, 1998). If reburning. The technique of reburn involves introducing a biomass is introduced directly as a reburn fuel, one proportion of the fuel, usually corresponding to 10–30% of disadvantage of biomass cofiring, namely that constituents in

Experience of indirect cofiring of biomass and coal 15 Biomass cofiring the biomass could contaminate the coal ash, can occur. Hence, more recently, the feasibility of gasifying the biomass prior to its introduction as a reburn fuel has been investigated.

Storm and others (2000) have investigated the pyrolysis and gasification of different biomasses with special emphasis on the reburn potential of the product gas. The pyrolysis and gasification were carried out in a 30 kWe, laboratory-scale entrained flow reactor and in a 20 kWth, laboratory-scale fluidised bed reactor. For the reburn experiments a 30 kWth, pulverised fuel, combustion reactor was used. Biomass containing relatively low nitrogen contents in the raw fuel (straw, beech, miscanthus) and biomass with very high nitrogen contents (sawdust, sewage sludge) were investigated. The different types of biomass all reduced NOx emissions during reburn from the initial values of about 1200 mg/m3 to 200 mg/m3 for straw, beech and miscanthus and to about 160 mg/m3 for sawdust and sewage sludge. Pyrolysis gases generated at 800ºC demonstrated the highest NOx reduction efficiency. This was due to their high content of aliphatic and aromatic hydrocarbons. At this temperature, the optimum straw to coal ratio was 1.3 which is equivalent to 40% thermal input from straw.

Calla Energy partners and Gas Technology Institute are developing a biomass gasification-based cofiring project to produce 15 MWe from biomass and other opportunity fuels in eastern Kentucky, USA. The electricity and steam generated will be consumed in the nearby industrial park and excess electricity will be sold to the grid. The gasification plant will be based on the RENUGAS® technology and will process 360 t/d of sawdust and other opportunity fuels such as bark, demolition materials and waste wood to produce a low calorific fuel gas. Calla Energy intend to cofire this gas either with natural gas or coal in their steam boilers. The two designs being considered are either to cofire the clean syngas with natural gas or to use the syngas as a reburn fuel in a coal-fired CFBC (circulating fluidised bed combustion) boiler (Lau and others, 2001). Another concept which is under development is the Close-Coupled Gasification (CCG) in which gasification technology is combined with reburning techniques and with direct combustion of biomass products. A programme to evaluate the overall characteristics funded by the California Energy Commission started in summer 1999. The programme includes identifying the most promising feedstocks via laboratory-scale gasification screening tests simulating conditions of a biomass boiler in a pilot-scale combustor. The pilot-scale system consists of an air-lock biomass screw feeder, a hybrid fluidised bed gasifier, a solid fuel test facility simulating a stoker boiler and the associated continuous emission monitoring (Rizeq and others, 2001). The application of this technology on full- scale plant is demonstrated at the Zeltweg plant which is described in Section 3.5.

16 IEA CLEAN COAL CENTRE 3 Indirect cofiring plants

The majority of plant which cofire coal and biomass involve hopper where two screw conveyers transport the straw to the direct cofiring. Those which indirectly cofire the two fuels grate-fired boiler. There are four parallel feeding systems. In are fewer in number and these will be described in this the event of fire there are three fire breaks to prevent the fire chapter. The plants considered are Amergas, Kymijärvi and reaching the straw storage area. In the furnace the straw is Zeltweg which gasify the biomass and Aabenraa, Avedøre 2 combusted by adding ignition air with high velocity around and Västerås which combust the biomass. the straw entrance. Primary air is introduced under the water- cooled vibration grate and secondary air through a number of 3.1 Aabenraa nozzles depending on boiler load. The woodchip is unloaded in a tipping pit, conveyed via a magnetic separator and In 1993 the Danish Parliament directed that Danish utilities shredder and then stored in a 6000 m3 silo which is sufficient must utilise 1.2 million tonnes of straw and 0.2 million space for 14 days supply. The silo is open to avoid mould tonnes of wood chips each year after the year 2000 in order problems. The plant is designed for firing woodchip having to reduce CO2 emissions. In 1997, the proportions of straw an average moisture content of 45% and in the range and wood chips were changed but the overall goal of 20–60%. A tube feeder is installed across the whole width of 1.4 million tonnes of biofuels remained. In response the the silo which rotates slowly moving the woodchip to the Danish utility ELSAM A/S initiated several pilot projects feeding silo. The fuel is then blown into the grate-fired utilising biomass including one at the existing Enstedværket boiler. If required, woodchip can be used as 20% of the fuel coal-fired plant in Aabenraa where a biomass boiler was for the straw boiler. installed in parallel with the existing Unit 3 of the coal-fired station. A separate unit was chosen to fire the biofuels as Feed water for the biomass boiler is extracted from the straw is highly corrosive at temperatures needed to generate existing feed water tank to a separate feed water tank from electricity and furthermore the contamination of coal ash which it is pumped to a common economiser. The water flow with straw residues creates problems for the use of ash in then splits and is conducted to further heating surfaces in the cement production. The two boilers at Enstedværket are only straw boiler and the woodchip superheater. The grates are connected via a common feedwater pipe from the condenser also coupled as economiser heating surfaces. Steam from the and a common steam pipe leading to the high-pressure steam coal and biomass boiler is mixed before reaching the high- turbine. The flue gases from the two boilers are separate and pressure steam turbine and is then returned to the coal there is no possibility of corrosion of the coal-fired boiler boiler’s reheater. Though this results in minor changes to the due to biomass firing. The biomass boiler supplies steam coal boiler’s heat flow and thermal absorption, it does not corresponding to 40 MWe and the coal-fired unit has an affect boiler efficiency. A process diagram of the plant is output capacity of 660 MWe or 630 MWe and 85 MW of shown in Figure 5. The flue gas from the woodchip district heating (CADDET, 2000; Havgaard, 1998; superheater combines with flue gas from the straw boiler and Ramsgaard-Nielsen, 1998). the excess heat is used to pre-heat feed water and combustion air. The flue gas then passes through a SNCR The biomass boiler is a Benson type boiler and was installed system for NOx control and an ESP. in an existing boiler house where a conventional coal-fired boiler had recently been taken out of service. The biomass The biomass plant was commissioned between June 1997 boiler is the largest straw-fired boiler in operation in the world and the first straw-fired Benson-type boiler. Re-using the existing infrastructure including the precipitators and the chimney reduced costs. The biomass boiler contains two filter boilers generating 120 t/h of steam. The first fired by straw steam turbine raises the steam parameters to 470ºC/21.5 MPa. The cleaning woodchip-fired boiler acts as the final superheater raising the processes steam parameters to 542ºC/20.0 MPa. Woodchip does not biomass superheater ash contain as much chloride as straw and can be fired at higher temperatures without damaging the boiler. The pressure in coal boiler the biomass boiler depends on the load in the coal-fired straw boiler and ranges from 12.0 to 21.5 MPa. The plant is boiler condenser wood coal designed to consume 120,000 t/y of straw and 30,000 t/y of chips woodchips. In 1999 the actual consumption was 87,792 tonnes of straw and 21,568 tonnes of woodchips. The straw straw is supplied by contracts with local farmers and the woodchip from three suppliers within a 200 km radius. Straw, per unit of energy, takes up ten times as much space as coal and the biomass slag coal slag straw store has room for 24 hours consumption. The maximum acceptable mean moisture content of the straw is Figure 5 Process diagram of the Aabenraa plant 23%. The straw bales are loosened and then fall into a fuel (CADDET, 2000)

Experience of indirect cofiring of biomass and coal 17 Indirect cofiring plants and June 1998 and was fully operational in August 1998. In controlled by soot blowing. There have been difficulties with 1998, 58% of planned biomass capacity was reached and establishing stable combustion conditions on the wood chip 73% was reached in 1999. The main reason for reduced fired grate and problems with overfilling the grate and with availability and load reductions were straw feeding line trips fuel and slag sintering. This has been partly due to blocked but these have been reduced considerably by preventative primary air holes and leakage between the two grate maintenance. The straw which was fired during sections. It has been necessary to rebuild the grate to a commissioning was from a dry harvest and fired well in the membrane wall construction. In December 1998 corrosion boiler. The more humid and varying straw quality in late was observed in the lower part of wood chip superheater 1998 created problems with momentary O2 drops under the furnace walls. The worst attacked wall tubes were repaired boiler trip limit of 0.5% and it was necessary to improve by overlay welding with Inconel 625. Further severe combustion air control. In 1998 there was some damage to corrosion was observed in 2000 this was repaired by overlay the grate driving mechanism and in June 1999 there was welding of the entire furnace with Inconel 625 in the second further damage to the grate and the ash hopper. During a half of 2000. Following this, from March 2001 the planned outage in March 2000 a new composite lined bottom superheater has operated satisfactorily (Ramsgaard-Nielsen, ash hopper with water nozzles was installed and the grate 2002). driving mechanism was improved and some of the grate headers were shortened. Since April 2000 the grate and ash Tables 11 and 12 show that the fuels that have been utilised hopper have operated satisfactorily. No severe corrosion has have been within the fuel specifications. Regarding the been observed on superheater, economiser or air heater environmental emissions, the dust emissions are typically surfaces and what thin deposits that do occur have been below 20 mg/m3, HCl emissions in the range 30–80 mg/m3,

Table 11 Aabenraa straw analysis (Ramsgaard-Nielson and others, 2000)

unit, dry basis Test 1-5 Spec. design Spec. variation

moisture, as received. %wt 12.6-16.0 14 8-23

ash %wt 4.7-5.5 4.5 2-7

HHV MJ/kg 18.4-18.8 19.0

LHV, as received. MJ/kg 14.9 12.3-16.9

C %wt 44.0-47.7 47.5 47-48

H %wt 5.6-6.1 5.9 5.4-6.4

N %wt 0.60-0.83 0.7 0.3-1.1

K %wt 0.94-1.19 1.0 0.2-1.9

Cl %wt 0.25-0.36 0.4 0.1-1.1

S %wt 0.12-0.13 0.15 0.1-0.2

Table 12 Aabenraa wood chip analysis (Ramsgaard-Nielson and others, 2000)

Unit, dry basis Test 1-5 Spec. design Spec. variation

moisture, as received %wt 34-55 45 20-60

ash %wt 0.72-1.9 1 0.3-6

HHV MJ/kg 19.8-20.5 20.5

LHV, as received MJ/kg 9.5 5.9-15.9

C %wt 47.5-51.9 50 49-52

H %wt 6.0-6.4 5.8 5.2-6.1

N %wt 0.18-0.25 0.3 0.1-0.7

K %wt 0.055-0.1 0.1 0.05-0.4

Cl %wt 0.01-0.03 0.02 <0.1

S %wt 0.01-0.02 0.05 <0.1

18 IEA CLEAN COAL CENTRE Indirect cofiring plants

Table 13 Aabenraa emissions (mg/m3,dry) Table 15 Aabenraa 1999 operational costs (Ramsgaard-Nielson and others, 2000) (Ramsgaard-Nielson and others, 2000)

Test e 1 2 3 4 5 6 million % no Fuel 5.84 43.5 Dust 2.4 1.3 15.1 10.4 1.7 6.6 Bottom and fly ash 0.11 0.82 NOx 259 228 222 160 181 195 Treated water, aux. steam 0.03 0.22 SO2 203 130 98 69 129 190 Operation 1.16 8.65 HCl 50 53 – – – – Maintenance 0.86 6.43 CO 479 61 70 131 47 63 Capital 5.43 40.4 O2 4.7 7.8 6.1 10.6 6.2 6.3 Total 13.43 100.0

District heat sales 0.45 3.36 Table 14 Production data for Aabenraa biomass boiler (Ramsgaard-Nielson and others, Net total 12.98 96.6 2000)

Straw Wood chip Electricity consumption, consumption, production, emissions by 190,000 t/y. The total project cost was t t MWh 400 million Danish Krone ($48 million) at 1995 prices including all system design and commissioning costs. The 1999 plant was financed by ELSAM A/S. The operational costs 1st quarter 23,801 6,449 40,243 for 1999 are shown in Table 15. The capital cost is based on a pay-back of the investment of A58 million over 15 years at 2nd quarter 21,056 5,070 39,259 an interest rate of 5% per annum.As the total electricity 3rd quarter 14,521 2,756 22,903 production in 1999 was 155,889 MWh, the generation cost was 0.083 A/kWh. Operation with the designed biomass 4th quarter 28,414 7,293 53,484 capacity would reduce the generation cost to Total 87,792 21,568 155,889 0.067–0.074 A/kWh. The project is not currently competitive with conventional coal-fired generation but the project was 2000 undertaken to reduce CO2 emissions (CADDET, 2000; 1st quarter 21,593 12,761 41,817 Havgaard, 1998; Ramsgaard-Nielsen, 1998; Ramsgaard- Nielsen and others, 2000).

3 3.2 Amergas NOx emissions typically 150–300 mg/m and SO2 emissions 50–200 mg/m3 as shown in the measured results in Table 13. The Amergas biomass gasifier is located at the Amer power The bottom ash and the fly ash are separated. In Denmark station in Geertruidenberg, the Netherlands. The facility will ash can be used as fertiliser if it contains less than 0.5 mg/kg gasify demolition wood and fire the gas in the EPZ Cd on a dry basis. This is possible for the bottom ash which (Elektriciteits-Produktie Maatschappij Zuid Nederland) Amer is spread directly on fields. The fly ash from the precipitators power station, unit 9, which has a net production capacity of is landfilled as the cadmium concentration is too high but ash 600 MWe and 350 MWth. The impetus for the project was treatment is under consideration to enhance the potential for the trend in legislation to ban the disposal of wastes with a reuse. certain heating value, the need to reduce CO2 emissions and the potential of modern coal fired plant to fire low grade The biomass boiler is operated at full capacity when the fuels cleanly and efficiently. Demolition wood, which is coal-fired boiler is operating between 40% and 100% utilised at the Amergas biomass plant, is waste wood capacity. It can be run alone to meet the district heating contaminated with paint, glue, etc, and cannot be recycled in demands. In 1999, the biomass boiler was operated at 100% the wood chip industry. Because of the contaminants it load on weekdays and 35% at weekends. It operates for contains, its ash has to be kept separate from coal ash. Hence 6000 h/y and the production data for 1999 are shown in the wood is gasified in a separate plant and the product gas is Table 14. At 100% load, the 40 MWe is generated by the cleaned before firing in the existing coal boiler. The project biomass boiler with an efficiency of 40%. The installation of was designed to ensure high fuel flexibility such that the the biomass boiler has not affected the existing coal-fired plant will be able to accept a wide range of fuels in the boiler’s ability to operate alone. The present plant is flexible future. The fuel is utilised with high energy efficiency to and it is possible to switch fuels to meet economic and achieve a sizeable reduction in CO2 emissions. The firing of environmental targets. The biomass boiler saves 80,000 t/y of the secondary fuel will have minimal or no impact on the coal which corresponds to 7% of the station’s total existing Amer 9 power block in terms of dynamic response, consumption and this is equivalent to reducing CO2 capacity or availability. Nor will there be any deleterious

Experience of indirect cofiring of biomass and coal 19 Indirect cofiring plants effects on the emissions or the byproduct quality of the energy density, was addressed by having an optimised existing unit. The Amergas biomass project is owned equally logistic system. The contract for supplying the fuel was with by EPZ and Essent Energy Systems Zuid b.v. which is part one supplier. This eliminated the need to pre-treat the wood of Essent, one of the parent companies of EPZ (Willeboer, on site and enabled just-in-time deliveries. As the market for 2000a,b). biomass is poorly organised, a long term fuel contract was signed before the installation was ordered. The fuel contract A feasibility study for the project was conducted in 1995 but included continuous monitoring and the creation of a the project was put on hold in 1996 as the price of waste strategic store of 100,000 tonnes of wood which had to be wood became relatively high due to exports to Scandinavia. kept available throughout the operating period. It was The project was revived in 1997 when the Dutch government decided to utilise gasification rather than combustion as with decided to subsidise it and there was additional support from gasification, the gas volumes that need to be cleaned were the EU Thermie programme. The waste wood market was much smaller. Though gasification, especially in reconsidered and it was possible to obtain a long term fuel combination with a gas cooler and gas filter is quite new, the supply contract. The environmental permits were obtained in experience obtained by EPZ at the IGCC plant at Demkolec 1998 with no objections from the public. This was due to the proved to be important. Biomass conversions are more very low emissions with no waste water discharge. The feasible on a larger scale hence during the project project was coordinated by EPZ and the contracts were preparation stage, the scope of the project was increased awarded in 1998. The long term wood supply contract was from using 100,000 to 150,000 tonnes of biomass per year. awarded to the Dutch firm BOWIE which has much This increased rate will save the combustion of 70,000 experience in recycling. The plant installation contracts were tonnes of coal per year and the emission of 170,000 tonnes awarded as follows: Lurgi – gasification, gas cooling, gas of CO2 per year. The complexity of the conversion was cleaning; Heijmans – fuel logistics, wood receiving, storage simplified by incorporating the existing installation hence the and conveyor systems; Schelde – wood gas system in coal following systems or facilities have been shared: boiler including burners; Siemens – modifications to boiler ● steam and condensate systems; controls. The construction was started in October 1998 and ● cooling water systems, natural gas, instrument air; completed in 2000. ● injection of waste water bleed into coal boiler; ● control room and personnel. The use of biomass presents specific challenges which may not apply to conventional fuels. These relate to the following The fuel costs were reduced by using demolition wood. factors: There was a financial saving even allowing for additional ● low energy density; investment costs for gas cleaning. The overall capital cost of ● poorly organised market; the Amergas project was 80 to 90 million Dutch guilders ● relatively new conversion technologies; ($33–37.5 million). The project was expected to make a ● complex technologies; small financial profit. ● clean fuel expensive. A process diagram of the plant is shown in Figure 6. The In the Amergas project the first of the factors, relating to low chipped demolition wood will be transported to the plant by

gas cooling with steam production steam Amer electricity wood gas power station unit 9 heat wood feedwater wet chips scrubbing gasification ash filter water injection

ammonia removal

oil bed material separation

air oil emulsion ash NH3

fly ash bottom ash

Figure 6 Process diagram of the Amergas plant (Amergas, 1999)

20 IEA CLEAN COAL CENTRE Indirect cofiring plants truck and stored in a storage silo from which it will be via a cooling tower or river to the environment. However, continuously transferred to a day silo. This will feed the such plant are generally economically viable if the utilisation screw conveyor feeding system of the gasifier. The of the plant in cogeneration mode is as high as possible, atmospheric circulating fluidised bed (ACFB) gasifier will ideally over 7500 h/y (Evans, 1995/1996). The Avedøre 2 operate at temperatures between 850ºC and 950ºC and the plant was designed to fire coal as well as the other fuels but, bed consists of sand and possibly limestone or dolomite. The due to government regulations, it will only fire the other product gas will pass through a cyclone and is then cooled to fuels, though it could fire coal at a later stage. The a temperature of 220–240ºC. At this temperature the gas will construction of the plant is intended to shift generation away be dedusted in a bag filter to a clean gas specification of from coal, reduce emissions and increase the use of biomass. <10 mg/m3. The fly ash is partly recycled to the gasifier and Avedøre 2 was built by i/s Avedørevaerket 2, which is a joint the remainder transported to make construction materials. venture between ENERGI E2 and Sweden’s Vattenfall The dust-free gas will be quenched, scrubbed with water to (Modern Power Systems, 2000). remove mainly ammonia, reheated to 100ºC and fed to special burners in the existing coal-fired boiler. The waste 3.3.1 Multifuel design water from the scrubbing section is stripped to extract ammonia which is indirectly recycled to the gasifier. The The plant contains an innovative multi-fuel concept which bleed stream from the waste water system is injected to the combines the output from three separate combustion units coal boiler where it is evaporated and combusted. The output into one ultra-supercritical steam turbine system. It consists of the gasifier should generate 29 MWe at an efficiency of of a parallel powered combined cycle (PPCC) arrangement 34% net or 26 MWe + 15 MW heat in cogeneration mode at with a coal/natural gas/oil USC (ultra-supercritical) boiler, a an efficiency of 31% electrical and 18% heat (Willeboer, biomass combustion unit able to burn wood chips or straw 2000a,b; Amergas, 1999). and an aeroderivative gas turbine running in an integrated cycle (Modern Power Systems, 1996, 2000; S K Power, Functional dry testing of the plant started in November 1999 1996). The plant is schematically represented in Figure 7. and was completed in January 2000. Hot commissioning of The multifuel concept enables each fuel to be burnt the plant began with preheating the gasification system with separately. The exhaust gas from the gas turbine is used for natural gas and commissioning the steam boiler, gas relief preheating part of the condensate and part of the boiler systems including auxiliary systems. During this phase, feedwater thereby replacing bleed steam from the steam problems arose in operating the natural gas start-up burner of turbine. As the steam extracted from the steam turbine is the gasifier and this required burner modifications and reduced it produces more electricity. The boiler is not optimisation of process conditions. The next phase involved affected by whether the gas turbine is in operation or not as the introduction of wood as the fuel, which required the the feedwater temperature and flow are unaffected. Hence commissioning of all solids handling systems. The bottom the gas turbine can be swiftly brought in or out of load as ash discharge and the recycle system of the gasifier had to be required and is suitable for peaking. It has been designed for modified. Initially only wood gasification was tested, at least 400 start-ups per year (Fabricius, 2000). The linkage by-passing the wet gas cleaning system. The final phase of of the gas turbine and the USC unit results in more the commissioning tested all systems including the wood gas electricity being produced from the gas burnt in the gas burners in the existing boiler. Considerable problems arose turbine than if the same quantity of gas were burnt in a with fabric filter blockage and it was decided to replace them separate gas-fired plant. The effective efficiency of the with cyclones. At the same time the extent of gas cooling biomass unit is also increased as its steam is utilised in a will be changed and the biogas will be introduced into the larger and more efficient steam turbine than if it has its own boiler at higher temperatures. These modification are steam turbine (S K Power, 1996). The flexible plant design expected to be completed by summer 2002 (Willeboer, allows the load of the USC plant, the biomass boiler and the 2000a,b; Van Dijsseldonk, 2002). gas turbines to be varied within a wide range independently of each other. The biomass boiler can be kept at full load 3.3 Avedøre 2 when the steam turbine is operated in the load range 20–100%. One gas turbine can fire at full load when the On reclaimed land south of Copenhagen, ENERGI E2 has steam turbine operates in the load range 35–100% and both constructed the innovative Avedøre 2 power plant adjacent to gas turbines can be operated at full load when the steam the existing Avedøre 1 plant. ENERGI E2 was established in turbine operates in the load range 50–100%. Thus the June 2000 by the merger of S K Energi, KE Produktion and flexible design at Avedøre enables high efficiencies to be KE Energi. The plant is needed to meet the growing demand achieved over a wide load range, independently of changes for district heating in the Copenhagen metropolitan region. It in fuel constraints such as price and availability (Modern replaces the output of three old coal-fired plants in eastern Power Systems, 2000). Denmark. The existing Avedøre 1 plant is a coal/oil fired combined heat and power (CHP) plant with a rated output of Originally the primary fuel for the plant was to be natural 250 MWe or 215 MWe plus 330 MJ/s of district heating. The gas. The annual natural gas consumption would have been Avedøre 2 plant has the flexibility to fire coal/oil/natural gas about 600 million m3 which would have constituted about and biomass and has a capacity at full load of 570 MWe or 85% of total fuel consumption. Fuel oil would only be used 485 MWe plus 570 MJ/s of district heating. In cogeneration as a supplementary fuel mainly in very cold winter periods. mode very high fuel conversion efficiencies can be achieved Biomass would account for about 10% of the fuel as use is made of the waste heat which is normally rejected consumption. The multi-fuel concept enables the plant to

Experience of indirect cofiring of biomass and coal 21 Indirect cofiring plants

water to water to production of de-SOx deionised water unit de-salt unit steam NH3 turbine storage

generator main boiler flue gas deionisation cooling de-NOx unit tank water (SCR) condenser air ESP makeup condensate de-SOx unit flue gas from water cleaning straw fired boiler burners district heat HP limestone storage straw LP preheater preheater storage air preheater feedwater ash bin water to waste tank (big bags) water cleaning biomass boiler dewatering of gypsum fuel oil storage exhaust gas boilers gypsum bottom storage ash generators gas station gypsum flue gas to stack gas oil bag house turbines filter

ash air preheater natural gas fuel oil condensate straw steam

Figure 7 Avedore 2 plant schematic (Modern Power Systems, 2000)

Table 16 Overview of costs of different plant (assuming interest rate 5% over 30 years) (Noppenau, 1997)

Unit Coal USC Parallel GT Multifuel CC

Specific investment DM/kW 1900 650 1425 1125

Efficiency, gas/coal % 48.3/50.0 58 51.5/52.6 57.0

Operation & maintenance DM/MWh 11 6 9 7.5

Unit size MW 375 210 585 375/585

attain efficiencies of 48% for the main unit, 41–47% for the 2 will reduce the emissions of Eastern Denmark’s power biomass unit and 56–60% for the gas turbine. These stations of CO2 by 10%, NOx by 20% and SO2 by 30%. It efficiencies are for the condensing option when only replaces production from less efficient plants built in the electricity is produced. The overall fuel efficiency of the 1950s and 1960s and increases the use of natural gas and plant in cogeneration mode, with the maximum production biomass and decreases the use of coal (Modern Power of heat and electricity, is predicted to be 94% (gross). The Systems, 1996; Noppenau, 1997). very high efficiencies are possible because of the ultra- supercritical steam conditions and the synergistic effects The multi-fuel concept gives Avedøre 2 considerable obtained by connecting the units in a new advanced cycle. flexibility in terms of the choice of fuel. Although natural The plant will supply heat to the metropolitan region’s gas has advantages with respect to the environment, coal has district heating consumers and electricity to East Denmark’s advantages regarding security of supply and its price is grid. It is expected that the plant will supply heat for the generally more stable. Biomass does not produce any net district heating system for about 5000 hours per year greenhouse emissions. As both the gas and electricity (Fabricius, 2000). As part of an agreement between ENERGI markets become more liberalised the choice of fuel will be E2 and Vattenfall, 200 MWe of electricity from Avedøre 2 determined by generation costs. Table 16 gives a condensed can be dispatched to Sweden. In addition to meeting the overview of costs of different types of plant. The fuel cost of growing demand for electricity and district heating, Avedøre the natural gas supplied to the gas-fired unit will depend on

22 IEA CLEAN COAL CENTRE Indirect cofiring plants

3.0 recirculation system, in order to maintain reheat steam 25 years temperatures, especially when the biomass boiler is in 5% 2.5 operation. Hot flue gas is recirculated from the top of the SK 1995 boiler to the over burner nozzles. SK planning price 2.0 coal imported from Germany The unit contains an SCR system between the boiler and the air heater which is designed to achieve a 95% NOx 1.5 reduction. Particulates are removed downstream of the preheater by an ESP. The ESP is split into four electrical Natural gas price/coal price 1.0 fields and eight parallel bus sections and can process 3 50 100 150 200 250 300 994,000 m /h at 115–170ºC. The guaranteed range of outlet 3 Coal price in DM/t dust concentrations is 11–30 mg/m . Downstream of the ESP combined cycle SK concept coal unit is a two-step Noel-KRC, limestone/gypsum, wet scrubbing FGD plant. In this system SO2 absorption takes place in two discrete process loops located in a countercurrent absorber to Figure 8 Selection diagram for fossil-fired power produce gypsum. plant (Noppenau, 1996) The design steam conditions for the high pressure system are 30.5 MPa and 582ºC with a supply of 296.5 kg/s. The reheat system is designed for 7.4 MPa and 600ºC and can reheat up the utilisation factor if there is a high capital cost needed to to 321.6 kg/s when both the gas turbines and the biomass provide the gas supply infrastructure. In this case natural gas boiler are in operation. The furnace contains membrane walls will only be a viable fuel if the plant can use gas for base with helical tubing. The hopper is also made of helical load generation. The two oil crises in 1973 and 1979 have tubing to obtain the correct distribution at low loads. The demonstrated how fuel prices can increase unexpectedly. The membrane walls are made of 13CrMo44. The first platen advantage of Avedøre 2 is that depending on price and superheater is made of X20CrMoV121 and protects the other regulatory constraints the plant can fire anything between superheaters from radiation from the furnace. The cross flow 100% gas and 10% gas. The other choices that could have pitch of the first superheater elements of 800mm was been considered were to have built a coal-fired unit or a selected to minimise the consequences of ash deposition. In natural gas fired combined cycle plant. The choice of the order to avoid high temperature corrosion, the superheaters optimum concept depends on actual and relative prices of the are made of austenitic steel, TP347HFG, with high fuels and these considerations are shown in Figure 8. This chromium content (17–20%). The headers and the main figure suggests that for the most realistic actual coal and gas steam lines operate up to 621ºC and are made of the material prices, the parallel powered plant is the optimum choice P92, which is a 9% chromium steel. The high pressure (Noppenau, 1996; 1997). The Avedøre 2 plant cost about boiler/turbine link pipes also make extensive use of P92 and 3.8 billion Danish kroner ($453 million) including gas, the Avedøre project probably involves the most extensive electrical and district heating connections (Rönn, 2001). application of this material (Modern Power Systems, 2000). Since the decision was taken to use natural gas as the main 3.3.2 USC unit fuel, the spot price of electricity has fallen and the price of natural gas has risen. Hence in early 2001 it was decided to The main unit is a 380 MWe ultra-supercritical, Benson, use biofuel instead of gas and in 2002 the main boiler will be single-pass, boiler and steam turbine generator with a flue converted to use wood pellets. Wood pellets will be able to gas treatment plant. The main plant data are given in supply 70% of the maximum load for the unit. About half Table 17. The unit was originally intended to fire coal, gas or the biofuel will be procured from a parquet factory where oil, though initially only natural gas and some oil would Energi E2 has set up a wood pellet production plant. The have been used. The unit can be readily converted to fire coal remainder will be obtained from other sources including at a later stage, if required. Indeed the heat transfer surfaces those around the Baltic Sea and possibly Canada. Biofuels in the boiler were designed for coal firing. The plant was from the Baltic region will be transported by barge to designed and will be supplied by FLS miljo/BWE and is the Avedøre where the existing coal harbour and part of the third in a series of advanced boilers, the first two being conveyor belt system could be used (Rönn, 2001). Skaerbaek 3 and Nordjyllandsvaerket. The boiler is first fired with gas until the load is 20% when coal may be introduced. 3.3.3 Steam turbine Above 30% the boiler can be fired with an arbitrary mix of gas and coal. The tangential firing system contains 16 BWE The steam plant in pure condensation mode without the Low NOx burners. Since the feedwater temperature could be biomass boiler and the gas turbines can generate 390 MWe as high as 320ºC, the economiser has tubes of 13CrMo44 with an overall thermal efficiency of 49%. This very high with 15Mo3 fins. Reheater 1 is designed with 15Mo3 tubes figure is partly due to the low temperature of the cooling and 13CrMo44 fins as the reheater inlet temperature could water (10ºC) but mainly due to the design of the steam be as high as 358ºC. The furnace is relatively large at 12.25 turbine. The high performance blading at Avedøre has been x 12.25 m as it was originally designed for coal. The boiler developed with 3D steam profile and the advanced steam capacity is 800 MJ/s which corresponds to a gas flow of conditions, which are given in Table 17, are in the ultra 16.57 kg/s (20.6 m3/s). The boiler contains a flue gas supercritical range. The resulting gross heat rate in pure

Experience of indirect cofiring of biomass and coal 23 Indirect cofiring plants

Table 17 Avedøre 2 – main plant data (Modern Power Systems, 2000)

Overall plant Steam turbine electrical generator

Capacity at full load, gross (MWe) 460 (without gas turbines) Type Ansaldo Energia 50WT23E 600 (with gas turbines) Rated output (MVA) 565 Power factor 0.85 Capacity at full load, net 430 (without gas turbines) Rated voltage (kV) 19.5 Electricity-only mode (MWe) 570 (with gas turbines) Stator cooling water Rotor cooling hydrogen CHP mode (MWe/MJ/s heat) 360/480 (without gas turbines) 485/545 (with gas turbines) Gas turbine electrical generator Efficiency (%) 49 (without gas turbines) 51 (with gas turbines) Type Alstrom TR-30/68 Number 2 Fuel natural gas (USC boiler Rated output (MVA) 68.3 and gas turbines) Power factor 0.85 heavy fuel oil(USC boiler) Rated voltage (kV) 11.5 straw (biomass boiler) Cooling (stator/rotor) Air/indirect water (TEWAC)

Main boiler Steam turbine

Supplier FLS miljø/BWE Supplier Ansaldo Energia Type five cylinders, single reheat Type Once through, Benson, corner- Inlet pressure (bara) 300 fired (originally designed for coal) Inlet temp (°C) 580 Reheat inlet temp (°C) 600 Burners BWE low NOx, type 3AG-LN57 Nominal condenser 0.023 pressure (bara) Capacity (kg/s) HP RH Maximum electrical output (MWe) 535 296.5 284.4 Maximum heat output (MJ/s) 620 Maximum steam flow (kg/s) 336 Operating pressure (MPa) 30.5 6.42 (7.39 with Max final feedwater temp (°C) 320 biomass boiler) Operating steam temperature (°C) 582 600 Gas turbines Feedwater temperature (°C) 320 Model Rolls-Royce Industry, Trent Thermal data Number 2 Boiler capacity (MJ/s) 800.5 Capacity, ISO (MWe) 51.2 Capacity per burner (MJ/s) 57.2 Heat rate, ISO (kJ/KWh) 8662 Gas flow (kg/s) 16.6 Efficiency (%) 41.6 Combustion air flow (kg/s) 289.9 Pressure ratio 35 Flue gas flow (kg/s) 323.3 Exhaust temp (°C) 426 Thermal efficiency (%) 96.0 Exhaust mass flow (kg/s) 159.6

Emissions Emissions CO (mg/MJ) 59 NOx (mg/m3) 50 NOx (mg/MJ) 60 CO (vppm) 25

Biomass boiler

Supplier Ansaldo Vølund/Babcock Borsig Boiler firing capacity (MJ/s) 105 Power-AE Energietechnik Fuel (straw) flow (kg/s) 7.2 Combustion air flow (kg/s) 40.3 Type Once through, Benson, grate fired Flue gas flow (kg/s) 47.1 Thermal efficiency (%) 93.2

Outlet steam pressure (MPa) 31 down to 16 at full load Emissions Outlet steam temp (°C) 583 CO (mg/m3) 625 max Outlet steam capacity (kg/s) 40 NOx (mg/m3) 240 max Flue gas outlet temp (°C) 115 Feedwater temp (°C) 230 down to 180 at full load

24 IEA CLEAN COAL CENTRE Indirect cofiring plants condensing mode, without district heating, biomass boiler two plants. There are only a few constraints with regard to and gas turbine is 6680 kJ/kWh. The corresponding gross the relative sizes of the gas turbine and USC plant though to efficiency is 53.9% and this high efficiency target at Avedøre take full advantage of the synergy the output of the turbine is guaranteed for not just one or two operating points but for should not exceed a certain value. The operation of the gas as many as 26 points. The Avedøre steam turbine consists of turbine with the main unit in PPCC mode results in the one single-flow high-pressure (HP) turbine, one marginal efficiency being considerably higher than with a intermediate-pressure (IP1) turbine, one double-flow conventional gas turbine. The marginal efficiency (␩) can be intermediate-pressure (IP2) turbine and two double-flow defined as: ␩ ⌬ low-pressure turbines (LP1 and LP2). The system is = ( Est + Egt) / Qgas designed for full throttling admission and sliding pressure where: ⌬ operation (Modern Power Systems, 2000). Est is the additional output from the steam turbine due to less steam extracted for preheating Both the HP and the IP1 turbines are of standard reheat Egt is the net electrical output from the gas turbine turbine module design. In addition to minor modifications to and take account of differential expansion during transient Qgas is the fuel input power to the gas turbine. conditions, materials evaluated during the COST 501 programme have been incorporated in key components The marginal efficiency depends mainly on the following exposed to increased steam conditions. The steam enters the four factors: HP turbine at a pressure of 30 MPa and a temperature of ● gas turbine open cycle efficiency; 580ºC. After leaving the turbine the steam is reheated to ● gas turbine exhaust gas temperature; 600ºC in the main boiler before entering the first ● preheater pressure and temperature; intermediate turbine, IP1, which has extractions for high ● isentropic efficiency of the steam turbine. pressure and low pressure reheating. The steam then enters the second intermediate pressure turbine, IP2. This is an Hence the highest marginal efficiency is not necessarily asymmetric double flow turbine with different temperatures obtained with the highest open cycle efficiency. and pressures in each end extraction for two step heat transfer to the district heating system. The main steam flow The turbines are housed in bespoke enclosures, which are then enters two double flow turbines LP1 and LP2 through designed to comply with ambitious noise targets. The cross-over piping provided with butterfly-type valves. The enclosures contain all electrical and mechanical auxiliaries operation of these valves is coordinated with the main and this modular approach reduces site installation and control valves to ensure the efficient management of steam commissioning times and costs (Modern Power Systems, required for district heating versus electric power output 1996, 2000). from full opening for full condensing operation to almost complete closing for full back pressure operation. The two 3.3.5 Biomass plant LP turbines are designed to handle the maximum condensing flow at the condenser pressure of 0.0023 MPa with minimum The biomass plant consists of an indoor straw store, a boiler exhaust losses. The steam then enters a sea water cooled plant, an ash separator and a bottom ash and fly ash handling condenser. When the plant is in cogeneration mode, the plant. The biomass boiler has been designed and built by a steam entering the low pressure turbine is just sufficient to consortium of Ansaldo Vølund and Babcock Borsig Power – cool it (Modern Power Systems, 1996, 2000; S K Power, AE Energietechnik. It is the world’s largest and most 1996). efficient straw fired boiler with a straw consumption of 26.5 t/h and producing 40 MW electricity and 60 MJ/s heat. 3.3.4 Gas turbine plant The biomass boiler at Avedøre has been designed for 100% straw firing or mixed firing, with straw and wood chips. The The gas turbine plant at Avedøre contains two Industrial initial annual consumption of straw of 150,000 tonnes will Trent generating sets, supplied and maintained by Rolls effectively replace 90,000 tonnes of coal. The straw Royce plc. These provide peak load generation and also heat combustion system consists of the following components: condensate and feed water to the USC unit. In open cycle the ● straw feeding system; sets generate 50–60 MW at 42% efficiency. The turbines ● fire damper arrangements to prevent burning back; incorporate the Dry Low Emissions (DLE) combustion ● regulating straw feeding table; system and atmospheric emissions are limited to NOx levels ● straw disintegrator to reduce straw density; of 50 mg/m3 and CO levels of 25 mg/m3. The Trent turbines ● double stoker screws in water cooled channel to feed are the largest member of the RB211 family of engines straw into furnace; which are used in the aero industry. The Trent engines retain ● water cooled vibration grate. the same aero core intermediate and high pressure turbines and compressors though the aero fan is replaced by a two The composition of straw varies geographically on the stage low pressure compressor mounted on the third spool. species grown but a typical ultimate analysis is: The final two stages of the low pressure turbine have been Component Wt. Fraction redesigned specifically for industrial power generation Carbon 0.375 service. The flue gas from the turbine is used to preheat the Hydrogen 0.049 feed water for the main unit instead of extracting steam from Oxygen 0.351 the turbine. This results in a level of synergy between the Nitrogen 0.007

Experience of indirect cofiring of biomass and coal 25 Indirect cofiring plants

Water 0.165 January 2002. First power production to the grid took place Ash 0.052 in March 2002 (Ottosen, 2002). By April 2002, the biomass LHV (kJ/kg) 14,300 boiler had been commissioned and trial operation had begun. The boiler had operated under all load conditions using straw Straw also contains chlorine, sulphur and potassium. During and initial operating experience has been good. The fouling combustion straw produces large amounts of pyrolysis and in the furnace was slightly higher than expected and slagging gasification products. Up to 80% of the energy is released in was observed in superheaters 2 and 3. Over this short combustible gases such as CO, CH4, and H2. The high operating period visual inspections have not shown any pyrolysis and gasification rates make the primary combustion excessive signs of corrosion (Gilli and Brandstetter, 2002). zone very luminous, with a yellow flame indicating a high soot content. The clinker formed in the primary combustion 3.4 Kymijärvi3 zone is sensitive to the oxygen content of the flue gas and its melting point drops to 600–700ºC if oxygen is not available. Lahden Lämpövoima Oy is a Finnish power company Hence it is essential that the oxygen content is greater than producing power and district heat for the city of Lahti in zero in all parts of the boiler. The pyrolysis and gasification southern Finland. The company is owned in equal shares by products need to be directed into the boiler room where the the city of Lahti and by Fortum Oy which is the largest main combustion takes place. Burnout is facilitated by a high utility in Finland. Lahden Lämpövoima Oy operates the level of turbulence which is generated with the aid of a large Kymijärvi power plant which is located near Lahti. The vortex in the centre of the furnace. This vortex mixes the power plant was originally oil-fired but it was converted to pyrolysis and gasification products from the feeding table coal firing in 1982. The maximum power output is 167 MWe with the oxygen rich products from the last part of the with 240 MWth of district heating. The boiler is a Benson, vibration grate. once-through boiler with steam conditions of 125 kg/s, 540ºC/17 MPa and 540ºC/4 MPa reheat. The boiler is not The biomass boiler is a once-through Benson type boiler. As operated in the summer when the heat demand is low. In the the biomass boiler supplies the same turbine as the main spring and fall, the boiler operates at lower load with natural boiler, the steam parameters are the same, namely 31 MPa gas as the fuel. The boiler uses 180,000 t/y (1200 GWh/y) of and 583ºC. In the boiler, above the feed layer, ignition air is coal and about 800 GWh/y of natural gas. The plant fires injected into the straw. The ignition air must blow down into low-S coal (0.3–0.5% S) and does not have any sulphur the straw to fix the position of ignition hence the boiler wall removal system. The burners have flue gas recirculation and above the furnace is at an angle of 45º so that the nozzles staged combustion for NOx control. Different types of face the fed straw. Further up there are secondary air nozzles biofuels and wastes, corresponding to about 300 GWh/y are which push the pyrolysis and gasification products into the available locally and these fuels could substitute 15% of furnace. The boiler has vertical tubing in the combustion current fuel usage and 30% of coal usage. The biofuels chamber in several passes each with upward flow. Between include peat and demolition wood, and the waste is produced the passes are downcomers and in some cases special mixing from classified refuse from households, offices, shops and devices to distribute the water and steam evenly. Because of construction sites. In order to reduce fuel costs and to reduce the highly corrosive constituents in straw special care has environmental emissions, a gasification demonstration been taken to avoid fouling and corrosion, especially in the project has been undertaken at Kymijärvi to demonstrate a superheater. A melting slag layer protects the superheaters commercial scale gasification of a wet biofuel and the use of above the combustion chamber and in the horizontal pass. hot, raw, very low calorific gas directly in the existing boiler. This is common practice but the superheater outlet By utilising the existing power plant capacity, the biofuels temperature of 583ºC is unusual. The water walls of the and waste fuels are fired efficiently with low investment and combustion chamber form the evaporator. The superheater is operational costs. Moreover, only minor modifications are made of the austenitic material TP347HFG and the water required in the existing boiler and any problems with the walls are made of 13CrMo44. The steam from the biomass gasifier do not shut down the whole plant (Palonen and unit combines with steam from the main boiler before Nieminen, 1999a; Raskin and others, 2001). The plant is entering the turbine. Using the biomass steam in the main schematically represented in Figure 9. turbine allows higher efficiencies to be achieved than if it has its own smaller turbine, as the losses for a larger turbine are 3.4.1 Gasifier relatively lower than in a smaller turbine. The straw boiler has moderate steam conditions and can be constructed of The gasifier at Kymijärvi is of the ACFB (atmospheric well tested steel materials thus keeping corrosion at an circulating fluidised bed) type and consists of an inside acceptable level. Having the two boilers separate also allows refractory-lined steel vessel in which the fuel is gasified in a the ash to be utilised separately. The bottom ash from the hot fluidised gas-solid particle suspension. In the gasifier, the biomass boiler will be used as fertiliser. The flue gas from biofuel and the waste fuel are converted to combustible gas the boiler after passing through the air heater will pass at atmospheric pressure and a temperature of about 850ºC. through a bag filter which will remove more than 99% of the The system consists of a reactor in which the gasification ash particles. The maximum emissions from the boiler will takes place, a uniflow cyclone to separate the bed material be CO – 625 mg/m3 and NOx – 240 mg/m3 (Modern Power from the gas and a return pipe for returning the circulation Systems, 1996, 2000).The cost of the biomass boiler was material to the bottom of the gasifier. The gasification air is $58 million. The USC boiler and steam turbine started fed to the bottom of the reactor via an air distribution grid. operating in late 2001. The biomass boiler was fired in The gas velocity is sufficiently high to fluidise the particles

26 IEA CLEAN COAL CENTRE Indirect cofiring plants

350 MW 540°C/17 MPa CO reduction - 10% biomass 300 GWh/y - 15% fuel input 2

processing

power 600 GWh/y district heat 1000 GWh/y pulverised coal flames 50 MW

gasifier

gas flame

coal 1050 GWh/y - 50% fly ash bottom ash natural gas 650 GWh/y - 35%

Figure 9 Biomass gasification – Lahti project (Palonen and Niemenen, 1999a) and many of the particles are conveyed out of the reactor into 3.4.2 Fuels the uniflow cyclone. In this type of cyclone, unlike in a conventional one, the gas and solids flow the same direction The available local biofuels in the Lahti area are given in – downwards – and both the gas and solids are extracted Table 18. The recycled fuel (REF) is obtained from refuse from the bottom of the cyclone. produced by households, offices, shops and construction sites. The fuels are transported to the power plant in trucks. The fuel is fed into the lower part of the gasifier and the There are two receiving halls; one for REF and one for biofuel typically contains 20–60% water, 40–80% biofuels. The REF hall also processes coarse biofuels. In the combustibles and 1–2% ash. In the reactor, the biofuel REF hall, the trucks tip REF and coarse biofuels on the floor particles dry rapidly, pyrolysis occurs and the fuel is of the hall or into a pit after which they are crushed in a converted to gases, charcoal and tars. Part of the charcoal slowly rotating crusher. Trucks are also used to transport flows to the bottom of the bed and is oxidised, generating biofuels to the other receiving station. The transport heat. The products then flow upwards in the reactor and platforms of the trucks have conveyors which discharge the secondary stage reactions, some of which are heterogeneous biofuels and the fuel falls through a screen down on to the and some homogeneous take place. These reactions produce chain conveyor at the bottom of the bunker. The coarser a combustible gas which passes through the uniflow cyclone particles are separated by the screen and moved to the REF which separates the solids. These solids which contain char hall for crushing. The fuel is transported by conveyors after are returned to the gasifier and are combusted in the fluidised passing a magnetic separator and further crushing, if needed, bed. The coarse ash which accumulates at the bottom of the to a fuel storage silo. In addition to storing the fuel, the silo gasifier is removed with a water cooled bottom ash screw. A is used for homogenisation of the fuel mixture before it is major difference between gasifiers supplied in the mid-80s and the Kymijärvi gasifier is that with the latter it is not necessary to dry the fuel even if it has a moisture content of Table 18 Available fuels in the Lahti area (Kivela 60%. Some mechanical modifications have been made to and others, 2002) accommodate the types of fuels to be fired at Kymijärvi. Amount, Moisture, Fuels such as waste wood and shredded tyres can contain Fuel items such as nails and screws and the air distribution grid % of total % by weight and bottom ash extraction system have been designed to Sawdust 10 45-55 allow for their presence. The product gas from the gasifier is Wood residues (bark, wood fed directly from the gasifier to the boiler through the air 40 45-55 chips, etc) preheater to two burners located below the coal burners. If the fuel is wet the heating value of the gas is low. If the fuel Dry wood residues (plywood, 30 10-20 moisture is 50%, heating value of the fuel is about particle board cuttings, etc) 2.2 MJ/m3. The gas burners were specially designed using results from CFD modelling and pilot plant tests. Recycled fuel 20 10-30

Experience of indirect cofiring of biomass and coal 27 Indirect cofiring plants

designed and process measurements of product gas, bottom Table 19 Fuels processed at the Lahti gasifier ash and fly ash composition have been close to calculated (Makkonen and Hotta, 2002) values. The operating temperature of the gasifier has been 830–850ºC. The high moisture content of the fuels, which Fuel 1998 1999 2000 2001 has been between 45% and 58%, has resulted in low heating value of the product gas, typically in the range 1.6–2.4 MJ/m3. Biomass, % 71 57 63 61 The gasifier output varied between 35 and 55 MWth REF, % 22 23 29 26 depending on the moisture content of the gasifier fuel and the required gasifier load. Plastics, % – 13 7.4 12

Paper, % – 6 0.1 0.3 The major components of the product gas from the gasifier are given in Table 21 and the concentrations of trace Railway tyres 5.5 0.1 0.2 – pollutants are given in Table 22. The levels in Table 22 Shredded tyres 1.5 0.9 – – represent minimum levels which are obtained when gasifying non-contaminated fuels. The use of contaminated materials Total, tonnes 79900 106200 91800 116100 increases the concentrations of ammonia, hydrogen cyanide and alkalies. For example, the gasification of gluelam can increase ammonia to 3000–5000 mg/m3, hydrogen cyanide transported to the gasification building. The silo discharger to 200–300 mg/m3 and total alkaline content to 0.3 ppmw. has variable speed controls. There were also modest effects on the emissions from the main boiler when the gasifier was operated as given in Table Initially, the gasifier fuels consisted of mainly biofuels such 23. The most noticeable change was the 5–10% reduction in as bark, wood chips, sawdust and uncontaminated wood NOx emissions. The most likely reason for this reduction waste. Later on, other fuels have been used and the system was the cooling effect of the low calorific value, high for collecting REF was started at the end of 1997. The moisture product gas in the lower part of the boiler. amounts of REF that have been utilised are less than the capacity of the gasifier but are expected to increase. Other fuels such as railway sleepers and shredded tyres have also been used. Table 19 summarises the main fuels that have Table 21 Average Lahti product gas composition been used in the first four operating years. (Palonen and Nieminen, 1999a) Average concentration Gas component 3.4.3 Operating experience % vol, wet

The gasifier was connected to the main boiler in December CO2 12.9 1997 and combustion tests were performed in January 1998. CO 4.6 Since the end of January 1998, the gasifier has been in continuous operation other than for maintenance periods. H2 5.9 The operating record of the plant for the first four years is given in Table 20. The reliability during the first operational CxHy 3.4 period was excellent and what few problems arose related to N2 40.2 the fuel processing plant. The availability of the plant then decreased due to a lack of fuel and fuel processing problems. H2O 33.0 Regarding the gasifier plant, problems arose relating to the use of shredded tyres. The wire content of tyres was so high that the accumulated wires blocked the ash extraction Table 22 Typical concentrations of trace system. The gasifier has operated well with other fuels and pollutants at Lahti (Palonen and results have met expectations. The operating conditions Nieminen, 1999a) regarding temperature, pressure and flow rates have been as Concentration range, Gas component mg/m3, dry

NH3 800–1000 Table 20 Operating record of the Lahti gasifier (Makkonen and Hotta, 2002) HCN 25–45 HCl 30–90 1998 1999 2000 2001 H2S 50–80 Operating hours 4730 5460 4727 7089 benzene 7–12 Availability, % (exc 99.3 98.9 97.1 96.1 tars 7–12 heat-up periods) alkalis <0.1 Energy produced, 223 343 295 449 GWh particulates 6–10

28 IEA CLEAN COAL CENTRE Indirect cofiring plants

The inspection of boiler heat transfer surfaces during annual Table 23 Effect of Lahti gasifier on coal boiler maintenance showed no evidence of abnormal deposit emissions (Palonen and Nieminen, formation or high temperature corrosion. 1999a) The results from the first four years of operation have been Emission Change caused by gasifier very encouraging. During this period 1310 GWh of energy have been generated from the gasifier’s product gas. Several NOx decrease by 10 mg/MJ different types of fuel have been gasified and a total of SOx decrease by 20–25 mg/MJ 22,006 h of operation under gasification have been achieved. The average availability of the plant during this two year HCl increase by 5 mg/MJ period has been over 95% (Palonen and Nieminen, 1999a; CO no change Raskin and others, 2001; Makkonen and Hotta, 2002). The total cost of the project, including the gasification and fuel 3 Particulates decrease by 15 mg/m preparation plants, civil engineering, control and slight increase in some elements from instrumentation was A12 million with A3 million received Heavy metals low base level from the EU THERMIE programme. Other partners included Lahden Lämpövoima Oy, Foster Wheeler Energia Oy,Foster Dioxins No change Wheeler Service Oy and VTT (all in Finland), Elkraft Power Furans Company Ltd (Denmark) and Pilbrico Ab (Sweden) (Palonen PAH Benzenes and Nieminen, 1999a,b; Kivelä and others, 2002). There are Phenols proposals to construct another REF gasifier at Vantaa Energy’s Martinllakso coal-fired plant near Helsinki (Paavilainen, 2002). Following the success of the Lahti Furthermore, as the biofuels contain low sulphur levels, the project, the Belgian utility Electrabel is building a SO2 emissions deceased by 20–25 mg/MJ, which corresponds commercial CFB gasifier to connect to its existing Ruien to approximately a 10% reduction. However, as the chlorine coal-fired plant. The gasifier will gasify 100,000 tonnes of content of biofuels is greater than in coal, HCl emissions are wood to generate 17 MWe. The technology is based on the increased by 5 mg/MJ when the gasifier is in operation. REF BioCoComb project in which Electrabel participated and shredded tyres are both known to contain significant (Modern Power Systems, 2002b). chlorine levels. Heavy metal emissions with the gasifier were very low though higher than with coal alone. There was no 3.5 Zeltweg measurable increase in the emissions of trace organics such as dioxins and polycyclic aromatic hydrocarbons. The Austrian utility Verbund has installed a biomass gasifier at its 137 MWe coal-fired power plant in Zeltweg. The The main components of the gasifier bottom ash were the project title is BioCoComb which is an abbreviation for bed materials sand and limestone though there were small ‘Preparation for Biofuel for CoCombustion’. The project amounts of metal pieces and concrete, etc. The carbon involved gasifying bark, wood chips, etc, in a CFB gasifier content of the ash was typically less than 0.5% and there and feeding the product gas into the existing coal-fired boiler were negligible levels of chlorine. The ash contained trace to generate 10 MWth. The direct use of biomass by blending levels of several heavy metals such as Cd, Cr and Cu. The it in the coal feed was considered but was rejected as the concentrations of most metals were less than tens of ppm but existing mills were not suitable for grinding biomass. Other Cr, Cu and Zn were found in the hundreds of ppm range. factors which weighed against cofiring were that the When shredded tyres were used as a fuel, the Zn content of residence time in the boiler of 2–3s was adequate for the ash reached 3000 ppm. Leachability tests on the bottom pulverised coal but might not have been for pieces and chips ash showed that the trace metal leachabilities were low. The of biomass. There was the possibility of slagging of biomass amount of gasifier ash is only a small proportion (3–5%) of ashes as the melting points of biomass ashes were less than total main boiler ash. The operation of the gasifier had only a furnace wall temperatures. High temperature corrosion was small effect on the quality of the main boiler ash. There was possible if the biomass is like straw and contained chlorine. no change in the levels of unburnt carbon or alkalis. There Alkaline components in biomass ash could damage SCR was a small increase in the levels of some heavy metals. The catalysts. The existing ash quality and consequently its most significant change was the increase in zinc content usability could be affected by the biomass and furthermore when shredded tyres were used in the gasifier. There were no the higher water content of the biomass could adversely changes in the measured levels of trace organic species such affect boiler performance. Though direct cofiring was as dioxins in the ash. The results of leachability tests on the rejected, the other concepts considered were: main boiler ash were satisfactory and it was possible to ● combustion of biomass in separate unit and injecting the utilise the ash as before. flue gas into the existing boiler; ● combustion of biomass in a grate integrated in the Corrosion/deposit formation monitoring has been undertaken existing furnace; since November 1997. Fourteen probe tests including ● grinding the biomass in special mills and firing it in the reference tests were carried out in the first operating year. existing boiler; These have shown no indication of abnormal deposit ● gasifying the biomass and combusting the product in the formation, fouling or corrosion in any of the test coupons. existing boiler.

Experience of indirect cofiring of biomass and coal 29 Indirect cofiring plants

The first option results in large flue gas volumes and very biomass is transported to the coal boiler as sensible heat, large cross-sections of ducting to the main boiler. The second low calorific gas and fine combustible char particles. There option has the advantages of no heat losses and no are very few heat losses in the system and hence the complicated ducting but it does require considerable efficiency for biomass conversion to electricity is almost as modifications to the existing boiler and can only be high as for the main coal plant. The biomass is gasified in a attempted if there is sufficient space below the boiler. This is circulating fluidised bed. Sufficient air is injected to possible at the St Andrä plant, which is another power plant combust part of the biomass to generate the heat necessary owned by Verbund, but not at Zeltweg. The third option to gasify the rest. There is insufficient air to combust all the requires high energy consumption for milling the biomass biomass which is partially gasified. The product gas is and the milling behaviour of the biomass is dependent on its easily burnt in the coal boiler. The CFB technology has water content. It may be necessary for the biomass to be pre- several advantages for gasification. The relatively low dried. The first three options also have to be placed near the gasification temperatures of 800–850ºC are below the combustion chamber which is not always possible whereas critical ash melting points and prevent slagging. The high with the last option the gasifier can be erected some distance gas velocities in the CFB cause mechanical attrition of the from the existing boiler and there is greater flexibility in char which leave the gasifier as a fine powder which can be integrating the new system into the existing plant. Hence this completely combusted in the main boiler. As the product gas option was chosen for the Zeltweg plant. Further advantages is relatively clean, it can be burnt at a high temperature in of the BioCoComb concept are: the coal without incurring slagging. ● a low gas quality is sufficient and there is no need to pre-dry the biomass; As the biomass is only partially gasified, the residence time ● partial gasification is sufficient resulting in a smaller and of the fuel in the gasifier is relatively short and it is possible less expensive gasifier; to use a smaller hence cheaper reactor. There is no ● no gas cleaning or cooling is needed; requirement to pre-dry or mill the biomass. The maximum ● a relatively low temperature in the gasifier is sufficient size of the char particles in the product gas is determined by thus preventing slagging; the design of the gasifier and the following cyclone. Particles ● lower power plant emissions; which are too large to pass the hot gas cyclone are separated ● no major modifications to the existing boiler. and are returned to the gasifier via a siphon. As the product gas is combusted in the main boiler, a gas of low gas quality The Zeltweg power plant has been in operation since 1962. It is adequate and neither hot gas cleaning nor gas cooling are originally fired lignite but in 1982 it was converted to fire necessary. This reduces the cost of BioCoComb technology hard coal. The main steam data are 18.5 MPa/4.4 MPa compared to others requiring clean, dust and tar free high (HP/reheat) at 535ºC. An SNCR system to remove NOx was quality gas. However, the length of ducting from the gasifier installed in 1989 and a Lurgi FGD system in 1994. The plant to the boiler has to be kept to a minimum to minimise the is located in a rural region in Styria/Austria which has danger of hot gas escaping. The gasifier does not need to be considerable forest industry in the locality. Several partners adjacent to the boiler; at Zeltweg it is 22 m away outside the cooperated in the BioCoComb project. Verbund coordinated boiler house. Other than the opening for the inlet of the the project and operated the demonstration unit. ENEL product gas, no further changes to the existing boiler are (Italy) characterised reactor operation by measuring fuel necessary. In addition to reducing CO2 by coal substitution, inlet, gas outlet and solid waste. Electrabel (Belgium) it is also possible to reduce NOx production by using the performed software analysis of the gasification process. ESB product gas as a reburn fuel. No modifications regarding (Ireland) engineered control and measurement equipment. control and instrumentation are necessary and the coal boiler EVS (Denmark) analysed the long-term effects of can operate without the gasifier. The system is schematically co-combustion on the SCR plant. AE (Austria) supplied the represented in Figure 10. CFB reactor. The planing work for the project started in September 1996 and plant construction started eight months 3.5.2 Fuels later in May 1997. Hot commissioning took place in November 1997 with first gasification in mid-December. The main fuel for the boiler is coal which accounts for Further tests, measurements and monitoring have been about 97% of total fuel consumption. About 3% is biomass undertaken since then. The total costs of the BioCoComb and oil is used as a start-up fuel. Table 24 gives a typical project including, engineering, biomass storage, conveying biomass analysis. The biomass is bought from the region’s system, gasifier, connection to coal boiler, commissioning forest industries and is delivered by truck. The price is and monitoring were about A5.1 million. For a commercial based on energy content and is typically 7 A/MWh. The project on a larger scale (100 MWth) the total investment biomass is delivered mainly in the required particle size cost is estimated to be A10–14.5 million (Anderl and others, with a small proportion of oversize particles. The biomass is 1999; Mory and Tauschitz, 2000; Simader and Moritz, fed from the outdoor storage area using wheel-mounted 2001). loaders to a push feeder which has a capacity of 500 m3. This equates to the daily consumption of the gasifier. The 3.5.1 BioCoComb technology biomass is then conveyed passing a metal separator and shredder to a 20 m3 dosing silo. Any oversize pieces are cut In the BioCoComb process, the biomass is gasified to to the required size by the shredder. The biomass is fed produce a hot, low calorific value (LCV) gas which also from the dosing silo using a dosing screw, a belt conveyor contains fine char particles. Hence the energy from the weigher and a double rotary feeder to the gasifier. The

30 IEA CLEAN COAL CENTRE Indirect cofiring plants

stoker feeder metal separator

classifier intermediate bucket elevator fuel silo product-gas duct to boiler screw conveyor weighing cyclone belt conveyor compressed air

sand silo water cooling

ignition gas gasifier fuel chute light oil

oil burner air from external air preheater

cooling water ash cooling screw

ash rotary feeder

trailer

Figure 10 Zeltweg process scheme and technical details (Mory and Tauschitz, 2000)

Table 24 Zeltweg fuel composition (Mory and 3.5.3 Gasifier Tauschitz, 2000) The gasifier is of steel construction with a brick and concrete Spruce wood composition refractory inside. The gasification chamber is a vertical tube without internal mechanical components or heat exchangers. C, % 19.7 Fine sand of a specified size distribution is used as the bed H, % 2.4 material. The fluidising and combustion air is introduced into the chamber through an open nozzle grid at the bottom. The O, % 16.6 air is taken from the recuperator of the coal boiler at about 270ºC. In the gasifier, the biomass partly combusts in the N, % 0.2 lower part of the reactor increasing the temperature to 850ºC S, % 0.0 and partly gasifies in the upper part where there is a shortage of oxygen. The fuel particles remain in the fluidised bed ash, % 1.2 until, due to gasification and attrition, they are small enough moisture, % 60.0 to pass the cyclone. All the fine particles of wood char dust and ash leave the gasifier with the product through the hot LHV, kJ/kg, wet 6066 gas duct into the coal boiler. Larger particles are returned to the gasifier near the nozzle grid where there is sufficient double rotary feeder seals the slightly over-pressurised oxygen for combustion. A water-cooled screw conveyor at gasifier from the atmosphere. The feeder limits the fuel size the bottom of the gasifier allows for the removal of the bed to 30x30x100 mm. The conveying system has a capacity of material and incombustible items. The gasifier is shown in about 25 m3/h. Figure 11.

Experience of indirect cofiring of biomass and coal 31 Indirect cofiring plants

Table 25 Zeltweg main plant data (Mory and Tauschitz, 2000) hot gas duct Coal Biofuel

Thermal input 330 MWth 10 MWth

wood chips, bark, Origin Polish coal cyclone sawdust

Fuel consumption 47 t/h 2–4 t/h

Heating value 27 MJ/kg 2–5 MJ/m3 (gas) gasifier Internal consumption 7 kW/MWth 14 kW/MWth

Unconverted carbon to boiler 10 mol% Particle size of char dust to boiler 200 µm Air consumption 3.7 m3/h start preheated air burner biomass feeder performance have been noticed and no additional sootblowing has been required. The fact that CO levels have not increased suggests that biogas burnout is good. Reburning is clearly taking place as the 3% thermal input from biogas has reduced the ammonia requirement for the SNCR system by 10–15%.The output of the gasifier varied between 5 and 20 MWth depending on the humidity of the fuel. The composition of the biogas was similar to the sand discharger predicted composition given in Table 26. Up to October 2000, over 5000 tonnes of biomass and supplementary fuels have been gasified. There were some initial problems with the fuel conveying system such as bridges in the dosing silo and frozen biomass slipping on inclined belts but these have been more or less solved. Initial inspection of the gasifier following early operations did not detect any damage. The Figure 11 The BioCoComb gasifier (Mory and hot gas duct was clean with no tar deposits or sediments of Tauschitz, 2000) sand or fly ash.

The gasification system is almost fully automated and the During start-up the gasifier is operated in combustion mode. only personnel costs relate to the feeding of the biofuel When the operating temperature is reached, the changeover system. The average additional costs of operational and to gasification is possible and is performed by a controlled maintenance activities of the gasifier are approximately increase in fuel flow. Manual or automatic operation allows 0.17 ¢/kWhth or 17 A/h at the standard load of 10 MWth for switching from combustion to gasification mode. This switching period involves considerable change in air demand. During the combustion mode, the fuel flow regulates the bed temperature. During gasification, the air Table 26 Zeltweg gas composition at 60% fuel flow controls the conditions in the reactor and this can humidity (Mory and Tauschitz, 2000) compensate for unavoidable changes in the humidity of the biomass which can alter the temperature. The ignition and Gas composition Calculated, % Measured, % gasification performance of the gasifier are very good. The O 0.0 0.0 burnout of carbon is excellent with almost no carbon found 2 in the discharged bed material (<0.4%). The main plant data N2 38.1 43.6 are given in Table 25. CO 2.8 2.7

3.5.4 Boiler operation CO2 12.5 13.2 The hot product gas enters the boiler through specially CH4 0.0 1.1 designed burners to ensure rapid ignition, stable flame, deep H2 9.0 3.3 penetration and good mixing into the coal flame. The gas burner is located above the existing burners to maximise H2O 37.6 35.0 reburning. The combustion of the biogas in the coal boiler others 0.0 1.0 has not resulted in any problems. No changes in boiler

32 IEA CLEAN COAL CENTRE Indirect cofiring plants

(Anderl and others, 1999; Mory and Tauschitz, 2000; biomass. Coal firing alone will achieve 50% load. The Simader and Moritz, 2001). Due to economic and strategic design fuels are given in Table 27. The distinctive feature of reasons the Zeltweg power plant was shut down in April the compact CFB design is its unconventional solids 2001. This terminated the gasification project which had by separator which is fabricated with straight panel walls. The then demonstrated that the BioCoComb technology was straight panels are used in both the hot separator and in the technically sound and the generation costs were competitive solids return channel. Gas and solids flow into the separator for electricity production from biomass (Mory, 2002). from the combustion chamber through an inlet channel and the gas flows out through cylindrical vortex finders. The gas 3.6 Västerås flow is a swirling vortex even though the cross section of the separator is rectangular. In the return channel, the gas seal The Västerås CHP plant in Västerås City, Sweden, contains system is made with a cooled membrane structure which four units firing oil and pulverised coal. The overall capacity requires minimal space and allows the amount of refractory of the plant is 500 MWe and 900 MWdh (district heating). to be minimised. In this design most of the manufacturing Unit 4 started in 1973 as an oil-fired unit with a capacity of can be completed in the factory thus reducing field 220 MWe and 350 MWdh or 250 MWe in full condensing construction times and risks of unexpected delays. mode. It is a once-through boiler with reheat cycle having a main steam pressure of 17.1 MPa and a steam temperature of In addition, the boiler contains an integrated heat exchanger 540ºC. In 1983, Unit 4 was converted to coal firing with the (INTREX™) which utilises hot solids returned from the unit capacity being downrated to 155 MWe/250 MWdh or separator or solids taken straight from the furnace. This 180 MWe due to a reduction of steam flow from 750 t/h to integrated heat exchanger can replace in-furnace 550 t/h. A new boiler, Unit 5, has been constructed at superheaters or be part of the evaporative surface with more Väaterås to fire biomass. The new boiler connects to the efficient heat transfer properties. The system enables the existing turbine, condensate and feed water systems of furnace size to be smaller and the arrangement of Unit 4. Unit 5 produces 200 t/h of main steam and brings the superheaters and reheaters to be simpler. A further advantage Unit 4 turbine back to full production. The Unit 5 boiler is that by controlling heat transfer, the furnace temperature consumes 1.1 million m3 of biomass thus replacing 120,000 can be controlled to optimise emissions and combustion for a tonnes of coal per year which corresponds to a third of range of fuels with different calorific values over a wide load present usage. Emissions of CO2 are reduced by 340,000 range. Furthermore the INTREX™ heat exchanger used as a tonnes per year. The biomass boiler is a CFB boiler with superheater surface enables full superheater temperatures to natural circulation. A unique feature of the project is the be reached at lower loads than with conventional designs. connection of a once-through boiler and a natural circulation The hot solid material is fluidised in the heat exchanger with boiler, both with reheat, to a common turbine. Such an air at low fluidising velocities. Fluidising gas flows to the undertaking requires close scrutiny of the water chemistry as furnace from the top of the heat exchanger chamber. Erosion Unit 4 is oxygenated and Unit 5 is alkaline. Other areas of which is possible with conventional bubbling bed boilers is concern are the connection of feed water pumps and HP feed much less likely due to the smaller particle size and the low water heaters, the connection of main and reheat steam flows but still effective fluidising velocity. If the fuel does contain to the turbine and the division of the cold reheat steam flows harmful impurities, the solids separator reduces the to the two unit. It is intended that Unit 5 will be operated at concentration of impurities reaching the heat transfer surface full load time most of the time to maximise the usage of thus reducing the likelihood of corrosion. In the Västerås biomass whereas Unit 4 will follow the requirements of the boiler both the high temperature superheater and reheater are district heating network (Westin and Venäläinen, 2000a,b). of the INTREX™ design and this greatly reduces the risk of chlorine corrosion and fouling. In addition, the ability to 3.6.1 Biomass boiler control the heat transfer rate in the final reheater minimises the amount of spray water for reheat steam temperature The biomass boiler is of the Foster Wheeler modern compact control and increases plant efficiency. The steam parameters CFB design. It is capable of firing a broad range of fuels for the CFB boiler are the same as for the once through from different kinds of biomass to coal. It is designed to boiler as shown in Table 28. achieve full load with biomass fuels or cofiring coal and The boiler is designed to meet very low emission limits. NOx emissions are controlled by a SNCR system in the particle separator. There is an additional catalyst layer in the Table 27 Västerås fuel data (Westin and convective pass to reduce ammonia slip and further reduce Venäläinen, 2000b) NOx emissions. As the biomass fuels contain low sulphur levels, limestone addition is not required for the fluidised Fuel Moisture, % LHV, MJ/kg bed. However, limestone injection equipment is provided in case high sulphur fuels such as peat and coal are used. Dust Forest residues (chips) 40-55 7.6 - 10.9 emissions are controlled by a fabric filter. The emission Sawmill residues 30-55 7.2 - 13.6 limits for the boiler are given in Table 29. The flue gas is cooled downstream of the boiler by a condensing plant. In Peat 38-58 6.5 - 10.5 the first stage of the condensing plant the flue gas is cooled Coal (50% max) 6-13 21.8 - 26.5 to approximately 65ºC by district heating water. In the second stage the flue gas is cooled further with combustion

Experience of indirect cofiring of biomass and coal 33 Indirect cofiring plants

unchanged. However, boiler 5 has a drum type unit and Table 28 Steam parameters for Västerås coal and oxygenated feed water was considered to be unsuitable due biomass boilers (Westin and Venäläinen, to the higher conductivity of the boiler water and consequent 2000b) corrosion risks. Hence the location of the oxygen dosing to Boiler No 5 (CFB) No 4 (PC) the inlet of the feed water pumps of boiler 4 was changed. This arrangement allowed the feed water tank, which was Main steam common to both boilers, to have deaeration in operation and boiler 5 to be fed with oxygen free water whereas boiler 4 Flow, kg/s 55.5 152.8 continued to operate with oxygenated feed water. Pressure, MPa 17.1 17.1

Temperature, °C 540 540 3.6.4 Feed water pumps and heaters

Reheat steam The feed water pressure requirements of the two boilers is very different. Boiler 4 has a large pressure drop at full load, Flow, kg/s 48.0 138.5 due to its once through design and requires a high feed water Pressure, MPa 3.8 3.8 pressure. However, boiler 5 requires a lower feed water pressure as it has a smaller pressure drop. The feed water Temperature, °C 540 540 supply also has an important role in the control procedure, Net heat to steam, MW 157 427 particularly for the once through boiler. Hence it was decided that each boiler should have an independent source of feed water which would facilitate feed water control and optimise feed water pressure for each boiler. Thus a dedicated new Table 29 Emission limits for Västerås biomass feed water pump for Unit 5, which was designed for 100% boiler at full load (Westin and Venäläinen, capacity, was installed. The old pumps could be used a back- 2000b) up pumps for boiler 5. In which case the oxygen feeding to the inlets would be stopped and the control procedure SO , mg/m3 127 2 modified accordingly. The existing HP heaters have two NOx, mg/m3 51 parallel lines each designed for 60% of the original capacity of boiler 4. As the water chemistries of the boilers 4 and 5 are CO, mg/m3 204 different, the HP heater lines were separated and each line is

NH3 slip. ppm 5 used solely by one boiler. A new bypass line was added to the HP heaters so that both lines have independent bypass lines. particulates, mg/m3 20 3.6.5 Steam connections air in a regenerative air heater. After the second stage the flue The main steam from boiler 5 is fed to the existing turbine in gas temperature is approximately 35ºC and the water vapour one pipe which is divided into two pipes close to the turbine is largely condensed. The heat input to the district heating is and connected to both steam inlets of the HP turbine. A flow 42.5 MW which corresponds to 27% of the heat output of measurement is provided in the main steam line as well as a the boiler. check valve to prevent back flow of steam. The addition of a new boiler requires the cold reheat steam to be divided in the 3.6.2 Connection with existing plant correct proportions between the two boilers. The reheat steam for Unit 5 is extracted from one of the two existing The connection of a once-through boiler and a natural pipes which remove reheat steam form the HP turbine. The circulation boiler, both with reheat, to a common turbine is a new pipeline has a check valve similar to those in the unique feature of the plant. In the early stages of the project existing pipeline for boiler 4. In addition, a new control a working group was set up to assess possible challenges. valve was installed in each cold reheat pipes for boiler 4. A The following main areas were identified as areas of concern control valve for the cold reheat pipe to boiler 5 proved and these were subsequently resolved: unnecessary due to longer pipelines resulting in higher reheat ● water chemistry, as boiler 4 is oxygenated whereas 5 is pressure drop for boiler 5. The cold reheat steam flows were alkaline; divided in proportion to the measured main steam flows from ● connection of feed water pumps and HP feed water each boiler. Alarms and interlocks were installed based on heaters; the reheat steam temperature after the first stage reheater. If ● connecting main and reheat steam flows to common the temperature exceeds given limits the HP-bypass will turbine; open and allow more steam through the reheater. This ● dividing cold reheat steam flows to Unit 4 an Unit 5. procedure applies to both boilers. An overall flow diagram for the two units is shown in Figure 12. 3.6.3 Water chemistry 3.6.6 Boiler operation The existing boiler 4 has operated satisfactorily with oxygenated feed water for a decade, hence there was Boiler 4 operates with sliding main steam pressure and the requirement for the water chemistry of this unit to continue same procedure is intended for boiler 5. The steam pressure

34 IEA CLEAN COAL CENTRE Indirect cofiring plants

production capacity: combined power 210 MWe & heat 392 MWth flue gas full condensing 250 MWe condensing plant 42.5 MW economiser 12-17.1 MPa

superheater

reheater superheater max input fuel (coal) LT ≈ boiler 4 470 MW MT boiler 5 max input fuel (biomass) HT ≈ 173 MW generator reheater 4

reheat steam reheat M steam reheat

condenser (lake water)

district heat district heat

Figure 12 Overall flow diagram – Västerås units 4 & 5 (Westin and Venäläinen, 2000a) in boiler 4 varies from 17.1 MPa to 8 MPa depending on load. It is unusual to operate a natural circulation boiler over such a wide pressure range and an analysis of boiler 5 concluded that such an operating regime would not be possible due to evaporation in the economiser and excessive spray water flow. Hence the boiler 5 steam pressure is limited to a minimum of 12 MPa. Boiler 5 is base loaded and rapid load changes are generally not needed. Furthermore the turbine is controlled by the demand of the district heating network which changes slowly. Sliding pressure operation results in load changes causing changes in the main steam pressure. This can lead to variations of the water level in the boiler 5 steam drum. A control valve in the main steam line slows the rate of change of steam parameters particularly when the load and pressure is reduced. Thus the permitted load changes for boiler 5 have been limited to 1–2% of full load per minute (Westin and Venäläinen, 2000a,b). Unit 5 was started up in October 2000, two months ahead of schedule and is now in normal commercial operation. Unit 5 is typically operated at full load to maximise the use of biomass. The load on Unit 4 follows the requirements of the district heat network (Lundquist, 2001).

Experience of indirect cofiring of biomass and coal 35 4 Conclusions

There has been increasing interest in the use of biomass for and fouling. The constituents of the ash will change during power generation in recent years. The principal reason is that direct cofiring and this can affect ash utilisation and disposal the use of biomass can significantly reduce net CO2 options. Indirect or hybrid cofiring involves either pre- emissions. Other advantages of utilising biomass are that it gasifying the biofuel in a separate plant or firing the biofuel diversifies the power plant’s fuel portfolio, it can lead to in a separate combustor and routing the steam to the main reductions in SO2 and NOx emissions and that its use can turbine. This technology is less common than direct cofiring. help to dispose of a solid waste. There are some It has the major advantages that the coal ash is not disadvantages of firing biomass which relate to its supply, contaminated by any constituent of the biofuel and that these transportation and composition and these can be reduced if constituents cannot cause corrosion or slagging in the main the biomass is cofired with coal. Cofiring can be direct, plant. Furthermore the total biofuel capacity is not limited by where the biomass and coal are fired in the same boiler, or existing constraints imposed by installed hardware and any indirect, where the combustion or gasification of biomass problems with the biomass plant will not result in the whole occurs in a separate facility. This report concentrates on power plant being shut down. However, the major indirect cofiring which is taken to mean technologies in disadvantage of indirect firing is that installation costs are which the ash from the coal and biomass are kept separate. very much higher than for direct firing. Indirect cofiring is Indirect cofiring is less common than direct cofiring and the most suitable for biofuels containing relatively difficult report concentrates on the following plants which indirectly components or when it is particularly important to prevent cofire biomass: Aabenraa in Denmark, Amergas in the the coal ash from being contaminated. Netherlands, Avedøre 2 in Denmark, Kymijärvi in Finland, Zeltweg in Austria and Västerås in Sweden. There are several technologies for indirect cofiring. Upstream gasification involves gasifying the biofuel Cofiring biomass with coal has the potential to overcome upstream and firing the fuel gas which is produced in low some of the drawbacks of firing pure biomass. Cofiring does calorific bio(gas) burners. There are two main approaches to not involve the high capital costs of building a new biomass this technology, one offered by Lurgi (Germany) and the plant but the significantly lower costs of retrofitting an other offered by Foster Wheeler (Finland). An example of existing plant. Retrofitted boilers can fire biomass when the former is the Amergas plant and an example of the latter biomass supplies are plentiful but switch back to coal when is at Kymijärvi. A variation of the gasification concept which supplies are low. Cofiring increases the efficiency of energy involves pyrolysing the fuel was utilised at Zeltweg. An conversion by firing the biomass in a larger plant. Fluidised example of the completely separate combustion of biomass bed combustion either in bubbling or circulating bed boilers and feeding the steam produced to the main boiler is the has been commonly used for co-combustion of biofuels and Avedøre 2 plant. A comparative study of the different coal, particularly in Scandinavia. In the Netherlands and in biomass cofiring technologies has shown that the availability Germany biomass wastes, such as sewage sludge and and reliability of fluidised bed combustors were higher than demolition wood are cofired in relatively small percentages for gasifiers as combustion is a more established technology. in some coal-fired plant. In Austria biomass cofiring takes Direct cofiring incurs the lowest costs. Parallel combustion place mainly in the pulp and paper industries using their own and parallel gasification have similar costs but are more residues in small industrial boilers and in two large expensive than direct cofiring. Indirect cofiring technologies demonstration units. A survey of 21 biomass plants in seven are at least ten times more expensive than direct cofiring but European countries showed that biomass can be cofired with of these technologies Foster Wheeler gasification was the coal, peat and waste. The contribution of biomass in grate- least expensive. The majority of plants which cofire coal and fired boilers ranged from 20–95%, in fluidised-bed boilers biomass involve direct cofiring. Those which indirectly from 22–90%, in pulverised plant from 3–20% and in cofire the two fuels are fewer in number and these are gasifier plants from 3–8% of total plant fuel consumption. described in this report. The size of these plants ranged from <1 to 300 MWth. In the United States since the 1980s several cofiring trials have At Aabenraa in Denmark, a biomass boiler has been installed been successfully completed in a range of boiler types in parallel with an existing unit of the Enstedværket coal- (cyclones, pc, stokers, BFBs and CFBs) in plant having fired plant. A separate boiler was chosen as straw is highly capacities ranging from 15 to 500 MWe. Cyclone boilers corrosive and the contamination of coal ash with straw were found to be particularly suitable for cofiring biomass. residues would create problems for its use in cement The practical feasibility of such projects depends very much production. The two boilers are only connected via a on the price of biomass relative to coal and the availability of common feedwater pipe from the condenser and a common biomass within 80 or 160 km of the plant. steam pipe leading to a high-pressure steam turbine. The biomass boiler is the largest existing straw-fired boiler and Direct cofiring is relatively straightforward with low capital the first straw-fired Benson-type boiler. The biomass boiler costs but can lead to several technical concerns. The high supplies steam corresponding to 40 MWe and the coal-fired chlorine content of some biofuels such as straw can result in unit has an output of 660 MWe. The biomass plant was fully high temperature corrosion. The lower melting points of operational in August 1998 but has incurred problems with some cofired ashes can increase the likelihood of slagging corrosion which necessitated overlay welding the entire

36 IEA CLEAN COAL CENTRE Conclusions furnace in 2000. At 100% load, the biomass boiler has an wood chips in CFB gasifier and feeding the product gas into efficiency of 40% and it operates for 6000 h/y. the existing boiler to generate 10 MWth. In the BioCoComb process, the biomass is gasified to produce a hot, low The Amergas biomass gasifier which is located in calorific gas which also contains fine char particles. Hence Geertruidenberg, The Netherlands, will gasify demolition the energy from the biomass is transported to the coal boiler wood and fire it in the EPZ Amer power station, Unit 9, as sensible heat, low calorific gas and fine char particles. The which has a net capacity of 600 MWe and 350 MWth. first gasification took place in December 1997 and by Demolition wood is waste wood and the product gas is October 2000, 5000 tonnes of biomass and supplementary cleaned before being fired in the existing boiler. The use of fuels had been gasified. For economic and strategic reasons biomass will save the combustion of 70,000 tonnes of coal the main power station was shut down in April 2001 but by per annum. The plant utilises a Lurgi gasifier. The biomass then the project had demonstrated that the BioCoComb gasifier’s output is equivalent to 29 MWe or 26 MWe and process was technically sound and that the generation costs 15 MWth. Dry testing of the plant was completed in January were competitive for electricity production from biomass. 2000. During subsequent hot commissioning several problems have arisen and major modifications are being A new boiler has been constructed at the Västerås CHP plant undertaken which should be complete by summer 2002. in Sweden to fire biomass. The biomass boiler is a CFB boiler with natural circulation. It connects to the turbine, Avedøre 2 contains an innovative multi-fuel concept which condensate and feed water systems of the existing coal-fired combines the output from three separate combustion units Unit 4 which is a once-through boiler generating 180 MWe into one ultra-supercritical steam turbine system. It consists or 155 MWe and 250 MWdh. The biomass boiler will of a parallel powered combined cycle arrangement with a increase the production to 250 MWe or 220 MWe and coal/natural gas/oil USC boiler, a biomass combustion unit 350 MWdh. The biomass boiler consumes 1.1 million m3 of able to burn wood chips or straw and an aeroderivative gas biomass and replaces 120,000 tonnes of coal per year. It is turbine running in an integrated cycle. The plant has the capable of firing a broad range of fuels from different kinds capacity at full load of 570 MWe or 485 MWe plus 570 MJ/s of biomass to coal. The biomass boiler was started up in of district heating. The flexible design at Avedøre 2 enables October 2000 and is in commercial operation. high efficiencies to be achieved over a wide load range, independently of changes in fuel constraints such as price Indirect cofiring of biomass and coal has thus been and availability. The main unit is a 380 MWe ultra- demonstrated successfully at a small number of power supercritical, Benson, single-pass boiler and steam turbine plants. The technology is more expensive than direct cofiring generator with a flue gas treatment plant. The primary fuel and some of the projects have involved a level of subsidy. was intended to be natural gas constituting about 85% of The technique is particularly suitable for biomass containing total fuel consumption with biomass accounting for 10% but troublesome components or when the quality of the ash is of since then the spot price of electricity has fallen and the importance for subsequent sale or disposal. price of natural gas has risen hence in 2002 the main boiler will be converted to use wood pellets. The biomass boiler is a once-through Benson type boiler consuming 26.5 tonnes of straw per hour and producing 40 MW electricity and 60 MJ/s heat. It has been designed for 100% straw firing or mixed firing with straw and wood chips. The USC boiler started operating in late 2001 and the biomass boiler was fired in January 2002.

A gasification project has been undertaken at the Kymijärvi power plant in Finland to demonstrate commercial scale gasification of a wet biofuel and the use of hot, raw, low calorific gas directly into an existing coal-fired boiler which currently produces 167 MWe and 240 MWth of district heating. The gasifier is of the atmospheric circulating fluidised bed type and the gasifier fuels consist of biofuels such as bark, wood chips, saw dust and recycled fuel from households, offices, etc. The gasifier was connected to the main boiler in December 1997 and the gasifier output varies between 35 and 55 MWth depending on the moisture content of the gasifier fuel and the required gasifier load. During the first four years of operation 1310 GWh of energy has been generated from the gasifier’s product gas and the average availability has been over 95%.

The Austrian utility Verbund has installed a biomass gasifier at its 137 MWe coal-fired plant in Zeltweg. The project, which is known as BioCoComb, involves gasifying bark and

Experience of indirect cofiring of biomass and coal 37 5 References

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Experience of indirect cofiring of biomass and coal 39 notes

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