Energia Electrica a Partir de Biomasa

8/18/2019 Energia Electrica a Partir de Biomasa

http://slidepdf.com/reader/full/energia-electrica-a-partir-de-biomasa 1/29

......................................................................................................

Power production from biomass

......................................................................................................

Thermal Generation Study Committee

......................................................................................................

April 1997

Ref : 02001Ren9788



The “Union of the Electricity Industry – EURELECTRIC” has been formed through a merger of the two associations

and

The Union of the Electricity Industry - EURELECTRIC, formed as a result of a merger inDecember 1999 of the twin Electricity Industry Associations, UNIPEDE

1 and EURELECTRIC

2, is the

sole sector association representing the common interests of the European Electricity Industry and itsworldwide affiliates and associates.

Its mission is to contribute to the development and competitiveness of the Electricity Industry and topromote the role of electricity in the advancement of society.

As a centre of strategic expertise, theUnion of the Electricity Industry - EURELECTRIC willidentify and represent the common interests of its members and assist them in formulating commonsolutions to be implemented and incoordinating and carrying out the necessary actions. To that end itwill also act in liaison with other international associations and organisations, respecting the specificmissions and responsibilities of these organisations.

The Union of the Electricity Industry - EURELECTRIC is also the association of the ElectricityIndustry within the European Union representing it in public affairs, in particular in relation to theinstitutions of the EU and other international organisations, in order to promote the interests of its

members at a political level and to create awareness of its policies.

The reports published by EURELECTRIC are the result of the work of its structure of expertise: theyrepresent one of the most direct methods of circulating knowledge and information throughout thesector, on subjects of common interest.

They are intended for wide circulation both within the electricity supply industry and outside it.

Ä Please do not hesitate to ask for the latest available printedEURELECTRIC publications

catalogue (with summaries of EURELECTRIC reports) from:

Union of the Electricity Industry – EURELECTRIC

Documentation

66 Boulevard de l'ImpératriceBE-1000 Brussels

BELGIUM

Tel: +32 2 515 10 00

Fax: +32 2 515 10 10

Email: [email protected]

Ä You can also use the EURELECTRIC Internet Web site, which provides the followinginformation:

- EURELECTRIC general information

- EURELECTRIC positions and statements

- Events & Conferences

- Publications Catalogue

http://www.eurelectric.org

1

International Union of Producers and Distributors of Electrical Energy2 European Grouping of Electricity Undertakings



Power production from biomass

............................................................................................

Thermal generation study committee

............................................................................................

Paper prepared by:

Dr.-Ing. Klaus WEINZIERL (Chairman) (VEW Energie Aktiengesellschaft,

Germany); Martti ÄIJÄLÄ (Imatran Voima Oy, Finland); Owe O. SANDIN(Vattenfall International, Sweden); Fritz LUXHOI (ELSAMPROJEKT A/S,Denmark ); Nico DOETS (N.V.EPZ, Netherlands); Philippe JAUD (EDF,France); Dr. ir. J.P. LEMMENS (ELECTRABEL, Belgium); IgnacioMENDEZ de VIGO (ELCOGAS, S.A., Spain); Giorgio DODERO (ENEL,Italy); Rui ALMIRO (EDP, Portugal) in cooperation with Olli HEINONEN(Imatran Voima Oy, Finland)

Copyright ©Union of the Electricity Industry - EURELECTRIC, 2000

All rights reserved

Printed at EURELECTRIC, Brussels (Belgium)



TABLE OF CONTENTS

Page

1. INTRODUCTION.......................................................................................................................... 1

2. USE AND HANDLING OF BIOMASS FUELS.................................. ........................................... 1

2.1 Use of biomass fuels................................................................................................................ 12.2 Handling of biomass fuels....................................................................................................... 2

3. POWER PRODUCTION TECHNOLOGIES.................................................................................. 3

4. FLUIDISED BED COMBUSTION ................................................................................................ 4

4.1 Fluidised bed combustion systems........................................................................................... 44.2 Development trends..................................................................... ........................................... 44.3 Technical requirements in biomass combustion....................................................................... 5

4.4 Emission control..................................................................................................................... 65. CO-COMBUSTION OF BIOMASS AND COAL........................................................................... 8

5.1 General................................................................................................................................... 85.2 Pulverised combustion of biomass........................................................................................... 95.3 Fluidised bed / grate firing incorporated in existing boiler .....................................................105.4 Separate combustor/gasifier unit ............................................................................................11

6. GASIFICATION...........................................................................................................................13

6.1 Background of gasification ....................................................................................................136.2 Technical description.............................................................................................................146.3 Technologies and projects............................................................ ..........................................18

7. ECONOMICS AND FUTURE OUTLOOK......................................... ..........................................207.1 Economics.............................................................................................................................207.2 Future outlook .......................................................................................................................22



02001Ren9788 April 19971

1. INTRODUCTION

Discussion about the strengthening greenhouse effect, carbon dioxide -based tax on fossil fuels,difficulties with the overproduction in agriculture and increased use of the CHP plants (Combined Heat andPower) have all increased interest in biomass-based power production.

The resources of biomass vary greatly, but are most typically wood-based fuels and wastes such as bark, wood chips, and saw dust; agricultural wastes such as straw, olive waste, almond nut shells, and ricehusk; and sludges from paper mills and de-inking plants. There is discussion going on what is waste and whatis biomass. In this report, municipal solid waste (MSW) is not considered as biomass.

Biomass fuels are very diversified, and their properties vary greatly. Therefore, it is not possible todiscuss all properties of all biomass. It is better to discuss various technologies used in power production andwhat has to be taken into account when estimating different technologies for different biomass fuels.

In order to limit the amount of technologies, the following key technologies have been discussed in

this report:- Fluidised bed combustion- Co-combustion of biomass and coal- Gasification

Other applied power production technologies, such as grate firing, have not been discussed in detail.There are also certain potential technologies under development, such as flash pyrolysis and the use of pyrolysisoil in diesel engines and gas turbines. All technologies have been treated as power plant technologies only, andin a rather large size class.

Special emphasis has been placed on gas cleaning systems and handling of biomass. Biomass fuelscontain significant amounts of alkalis, which create fouling and slagging problems. The highest alkali contents

are found in biomass fuels with rapid annual growth, such as straw, whereas stem wood is typically low inalkali.

In order to get a good view of the power production technologies for different biomass fuels thefollowing issues have been discussed:

- State of the art of the various technologies- Development trends- Use of different technologies for different biomass fuels

- Problems with alkalis, halogens as chlorine, heavy metals and trace elements- Use of additives for emission and bed agglomeration control- Avoidance of corrosion- Slagging and fouling problems

- Flexibility - Variations in heating value - Limitation of steam temperature due to alkalis and chlorine - Optimum operating conditions- Use of ash- Emission control and gas cleaning methods- Economy and prospects

2. USE AND HANDLING OF BIOMASS FUELS

2.1 Use of biomass fuels

Biomass fuels include a large variety of different materials. Wood-based biomass, such as industrialwood waste, bark and sludges from the forest industry, is the most important biomass fuel used in the energy production. The share of black liquor is significant, particularly in northern Europe. In central and southern



02001Ren9788 April 19972

Europe, more interest is directed to straw, other by-products of agriculture and non-arborescent plantscultivated particularly for energy use. Other biomass fuels are municipal sludges, biomass-based wastes and biogas.

Statistical data of the use of biomass in a certain country may vary greatly, depending on the source of

information. The reasons are different ways of preparing statistics and defining biomass. It is difficult to definethe current situation, but it is even more difficult to find a reliable estimation about the potential and theincrease of utilisation of biomass fuels in the future.

Energy production from biomass in the EU countries in 1994 is shown in Figure 2.1 (RenewableEnergy Sources Statistics 1989-1994, European Commission, Statistical Office of the European Communities).Municipal solid waste has been excluded (except Austria, where data was not available).

Heat production from biomass means in practice the use of wood in heating of buildings. In France, for example, nearly 9 Mtoe/a of firewood is used, with all the individual furnaces included. The use of firewood isconsiderable also in Germany, Italy, Spain, Austria, Finland and Sweden.

Major part of biomass used in power production consists of wood residues of the forest industry, and black liquor. They are used in combined process heat and power production. Finland and Sweden produce asignificant part of the total volume of electricity with biomass fuels.

2.2 Handling of biomass fuels

The energy content per volume of biomass is low, which means that the volume flows to be handledare large. Without any special arrangement, biomass cannot be stored for a long time in a receiving station of a power plant area, because of the tendency to decompose and large volumes, and deliveries must be arrangedcontinuously. With the necessary equipment, long term storage may be possible.

When biomass fuels are handled, the risk of fire or dust explosion must be taken into account. Also

smell and dust problems must be considered.

The fuel handling solutions to be chosen depend on the size of the plant, degree of automation, way of delivering, and quality of the fuel. The fuel handling equipment consists typically of the following parts:receiving station, weighing, screening, crushing, storage, conveyors, bunkers, fuel feeding and feedingmonitoring. In pressurised processes, such as pressurised gasification, fuel pressurising equipment is needed.

The handling equipment of solid fuel is usually the plant part that contains the greatest risk and causesmost of the cases of unavailability. Unavailability can be reduced by redundancy of the equipment and by being prepared to use alternative fuel in case of malfunctions. A lot of maintenance need is concentrated on the fuelhandling chain, and its maintenance expenses are high.

Receiving of solid fuel is usually arranged in the receiving station, where fuel is discharged. If the fuelis a sludge type of material, a pump can be used in transportation and even in feeding into the boiler, if necessary.

The fuel truck is weighed before and instantly after the unloading to measure the amount of fuel for billing. A sample of the fuel is taken for determining moisture content and heating value of the fuel. After this,the energy content can be calculated.

In order to make further fuel handling easier, the fuel can be screened. Oversized material is oftencrushed and recycled back to the fuel line. In certain combustion or gasification applications, the fuel must bemilled to be of a finer fraction quality than the received fuel.

The storage of fuel can be arranged either in the field, receiving station or intermediate storage, which

is a part of the handling chain. Usually biomass fuels are difficult to store for long periods without drying, because of moulding and decomposing.



02001Ren9788 April 19973

Conveyors are needed to transfer fuel from one handling stage to another and finally to the boiler or gasifier. With solid fuel belt conveyors, scraper conveyors and elevators are most frequently used. Fuel qualityand the lay out of the plant determine the handling equipment needed.

A biomass combustion plant usually has a fuel silo, which smooths out the fuel flow. Fuel is usuallyfed to the boiler using screw feeders. The fuel flow is controlled by the rotation speed of the screws.

The costs for handling and preparing the material can be in the size of 10-20% of the total plant costs.

3. POWER PRODUCTION TECHNOLOGIES

In principle, it is possible to use different types of technologies to convert biomass into energy, but thedominating technologies of today are: grate firing, fluidised bed combustion, co-combustion applications, andgasification.

Grate firing was the dominant combustion technology for solid fuels since the beginning of the

industrialism until 1980s in small and medium scale units. Since then, new combustion techniques, particularlythe fluidised bed combustion, have replaced grate firing to a great extent. In the small scale applications, below5 MWth, grate firing has remained the most common solution, but there is special market for larger applications, too. Biomass fuels have varying fuel characteristics, and therefore there is an extensive range of different grate constructions. Variety is increased also by the great number of manufacturers, which is due tothe small unit size and the varying local needs.

During the past twenty years, the development of the fluidised bed combustion has significantlyincreased the use of various biomass fuels in power and heat generation, and fluidised bed combustion has become the most common solution in new biomass-fired power plants. The pulp and paper industry has beenthe forerunner with its adequate supply of biomass fuel, and energy demand on site. Later on, municipalitiesand even utilities have seen biomass as a potential fuel.

The fluidised bed combustion technology has become the dominating technology also in the co-combustion applications, because it offers high fuel flexibility and high combustion efficiency with rather lowemissions. There are certain technical issues in co-combustion of biomass to be emphasised. Feeding of allselected fuels must be secured with appropriate design of fuel handling and feeding systems. Some biomassfuels contain environmentally harmful impurities such as heavy metals, alkalines or chlorine. Chlorine maycause corrosion risks. Ash of certain biomass fuels melts at a low temperature leading to slagging and fouling problems. These problems must be emphasised in the design of the co-combustion systems.

In pulverised coal-fired boilers, the co-combustion of biomass and coal can be implemented in manyways.

- In the direct co-combustion, biomass is mixed with coal prior to grinding, or there is a separate linefor pulverised biomass.

- Biomass is burnt in a fluidised bed or on a grate, which has been incorporated in the pulverised coalfired-boiler. Biomass is burnt at the bottom of the furnace, and pulverised coal is fired higher in thefurnace. This is used mainly in retrofit applications.

- Biomass is burnt or gasified in a separate unit, and heat of flue gases or the product gas is utilised inthe existing boiler.

In the gasification process, solid fuel is converted into a gaseous energy source that is easy to be usedand may offer improvements in efficiency. Biomass fuels are particularly suitable for gasifying, due to their high volatility content, high reactivity, and relatively low temperature requirement. Additional advantages arelow sulphur content, CO2- neutrality, and renewable fuel. Disadvantages of biomass fuels are: dispersity, highmoisture content, high alkali, and low bulk density. Most of the gasification processes are under development.



02001Ren9788 April 19974

4. FLUIDISED BED COMBUSTION

4.1 Fluidised bed combustion systems

The fluidised bed combustion was developed in the 1970s particularly for biomass and other low-gradefuels, which have typically large variations in fuel properties. The benefit of the FBC when using these fuels isthe large amount of bed material compared with the mass of the fuel (98% versus 2%) and thus the large heatcapacity of the bed material that stabilises the energy output caused by variations in fuel properties. The other advantages of the FBC, such as sulphur removal with limestone or dolomite and low NOx emissions, becameimportant in parallel with the new environmental requirements in the 1980s. Additional flue gas cleaningsystems may be required for certain biomass fuels.

Fluidised bed combustors are usually classified as either bubbling (BFB) or circulating fluidised beds(CFB) (Fig. 4.1). In a fluidised bed system, the solid bed material is normally made of inert material of fuel(such as sand and/or ash), and if needed a sorbent (such as limestone). The bed lays on a distribution plate.When stream of air or other gas passes through the plate nozzles, it lifts the solid particles.

In a BFB system, the air velocity is 1 - 3 m/s and the particles behave like a boiling fluid but stay inthe bed. In a CFB system, the air velocity is higher, 3 - 6 m/s, for example, and part of the bed material actuallyleaves the bed and is collected by cyclone separators before being recirculated to the bed (Fig. 4.2). Bothconcepts are operated at low temperatures from 800 °C to 950 °C, primarily to avoid the formation of thermal NOx, to avoid the melting of the bed material, and with sulphur containing fuels to make efficient use of calcium oxide-sulphur dioxide reaction for SO2 control. Despite the low bed temperature, the combustionefficiency is high, due to very high rates of heat and mass transfer between the gas and the particles, and due tostaging of the combustion air.

4.2 Development trends

Although FBCs and especially CFBs are being scaled-up to utility sizes, the dominating market for FBCs in the 1990s and at the beginning of the 2000s will be in industrial and district heating co-combustionand low-grade fuel applications. The development of FBC for new difficult fuels such as sludges, RDF, coalsrich in chlorine, and fuels with chlorine and high alkaline contents such as straw and some other biomass fuels,is a challenge for boiler manufactures, because of high temperature corrosion risks in the superheater tubesand/or fouling and slagging risks in the furnace.

BFB combustion is considered commercially and/or economically competitive in the plant size whichis normal to biomass combustion. CFB is favoured in fossil fuel and co-combustion applications, due to higher combustion efficiency, lower NOx emissions, efficient sulphur removal, better heat transfer, higher fuelflexibility and fewer fuel feeding points compared to BFB. BFBs are favoured when only biomass or similar high reactivity, low sulphur, high volatile content, and low-grade fuels are used. BFB has simpler design and

lower investment and maintenance cost than CFB. Plants that use biomass are typically smaller in size.

There are different development trends in the fluidised bed combustion:- To reduce the cost of boilers by making the boiler simpler and cheaper - To commercialise the technology at larger power plants (coal combustion)- To commercialise the technology at smaller power plants (biomass combustion)- To design the technology for more difficult fuels (higher alkaline content, lower melting point,

chlorine, lower heating value etc.)- Integrated solids removal systems- Fuel feeding and metering systems



02001Ren9788 April 19975

4.3 Technical requirements in biomass combustion

4.3.1 Boiler design

In the design of a boiler for biomass or co-combustion, the following requirements must be taken intoaccount:

- Combustion temperature control when firing different fuels of changing heating values.- Steam temperature control when having different flue gas flows resulting from high and low-grade

fuel.- Prevention of corrosion of superheaters due to chlorine.- Dimensioning of auxiliary equipment for different fuels (e.g. fuel handling, ash removal).- Design of fuel feeding systems for different fuel types.- Meeting the emission requirements with all the fuels which are selected to be used (SOx, NOx, N2O

etc.). Boiler design is not always sufficient, but flue gas treatment devices may be needed.

The fluidised bed combustion technology can meet these requirements in the following way:- Flexible air distribution system helps control combustion temperature and emissions with different

fuels. The effectiveness is very much up to the operator.- Use of flue gas recycling when firing high-grade fuels such as coal to control combustion

temperature, steam pressure and emissions.- Allowing sufficiently large margins when dimensioning auxiliary equipment to meet the

requirements of different fuels.- Use of double feeding and good control systems to ensure high availability in fuel feeding.- Ensuring homogeneous quality of the fuel.- Use of heat exchanger in bed material return or outside the furnace to control the combustion

temperature (CFB). This leads to better control of NOx emissions.

The density of biomass fuel is typically lower than that of the bed material or coal. Biomass fuels havealso a very high volatiles content and low carbon content. These properties change the combustion phenomena

when compared with coal. Biomass fuel migrates to the top of the dense bed, and volatile gases evolve quicklyand leave the bed before they are completely burnt. In a BFB, this means that significant portion of thecombustion takes place in the freeboard above the dense bed. The same trend has also been observed at CFBunits, where a substantial part of the combustion may take place in the upper part of the furnace. In addition toflexible and correct air distribution, efficient mixing of secondary air with the volatile gases and adequate gasresidence time should be ensured.

The ash content of most biomass fuels, such as wood, is quite low, typically less than five percent. Dueto the low ash content, it may be necessary to add additional solid material to the fluidised bed during operationto provide sufficient amount of bed material. The ash content of certain biomass fuels, such as straw, may berather high and the sodium and potassium content of the ash may contribute to the formation of constituents,which have low melting points. These constituents may form bed agglomerates or cause fouling of heat transfer surfaces.

4.3.2 Erosion and corrosion control

Fluidised bed boilers are susceptible to erosion problems with any fuel, since they operate with highrates of mass transfer. Some of the fluidised bed biomass facilities report problems with erosion. Corrosion hasmore to do with the specific fuels used than with the fluidised bed technology.

Selection of suitable materials and proper design are essential in order to minimise problems witherosion and corrosion. Protective measures against erosion at the critical points in the furnace, such as tube bends and the interface between the waterwall and the refractory, include: tube shields, hardened facing to thewaterwall tubes, and installation of fins and tube studs. In the lower part of the furnace, materials are exposedto changing oxidising/reducing conditions, and they are also subject to the chemical attack by impurities in thefuel.



02001Ren9788 April 19976

If biomass fuel is low in ash, it may be necessary to add additional solid material to the fluidised bed to provide sufficient amount of solid material for process reasons. Sand is usually the material selected, because itis inexpensive, readily available and it does not attrit easily. Sand, however, is primarily silica (SiO 2) and maylead to erosion concerns. Limestone or other softer materials can be used in the same way as the bed material inorder to reduce erosion concerns.

Certain biomass fuels contain substantial amounts of chlorine and sulphur. These constituents maylead to corrosion of the metal and refractory surfaces at the temperatures of the fluidised bed combustion.Limestone or other sorbents can be used to reduce corrosiveness of these components.

Under certain conditions, alkalis develop eutectics, which have a low melting point. These molten products, including sulphates of sodium, potassium, and calcium and sodium chloride, may attack fluidised bedcomponents and downstream components as they are deposited on the cooler surfaces.

Certain fluidised bed boilers burning biomass containing chlorine and alkalines have superheaters placed in a separate fluidised bed heat exchanger, where no fuel is fed. Fluidisation keeps most of the harmfulconstituents away from the surface and the superheaters can operate at a higher temperature without corrosion.

4.3.3 Fouling

Fouling problems at FBC boilers include often deposits, agglomerations, and sinters. Slagging isnormally avoided in FBCs, since they operate at temperatures below the ash softening point. Fouling of the heattransfer surfaces results in a reduction of heat transfer, and deposits and agglomerations may lead tooperational upsets. Critical areas of deposits are superheaters, uncooled walls and feeding openings.

Alkalis of the ash may lead to the development of low melting point compounds. Sodium and potassium are the primary constituents causing problems. Agricultural wastes, such as straw, are particularly bad with respect to alkali content. Certain fuels can not be burnt alone.

Fouling problems may be reduced by adding limestone or other sorbents, which increase the ashsoftening point, or by minimising the alkali build-up with frequent fresh bed make-up.

Operational measures, such as combustion temperature control, are also important. Control of theoperation may be problematic, because of the variation in the properties of fuel.

Deposits in the backpass occur due to molten/semimolten ash particles or condensation of vaporisedconstituents. Compounds containing potassium, sulphur and chlorine have been found to be the principal bonding agents. Deposits lead to reduced heat transfer, and potential corrosion when chlorine or sulphur is present. Deposit build-up can be minimised with a properly designed soot blowing system.

4.4 Emission control

4.4.1 Flue gas cleaning systems

The significant air pollutants from biomass fired FBC systems are usually SO 2, NOx, N2O, particulates, CO and CxHy. In certain cases, hydrogen chlorine (HCl), dioxin, furan and metals may becontrolled. Most biomass fuels contain low amounts of nitrogen, and NOx emissions can be reduced throughcareful design and control of the combustion process. The sulphur and chlorine contents are also typically low.Thus, an FBC system burning a typical wood-based biomass fuel may only require a particulate control device.

In many cases, emission control using the combustion technique is not sufficient, and additional fluegas treatment is needed. The following methods can be used in the flue gas treatment.

- Electrostatic precipitator (ESP)- Bag filter - Scrubber systems- Selective catalytic reduction (SCR)

- Selective non-catalytic reduction (SNCR)- Activated carbon filter



02001Ren9788 April 19977

- Use of various additives

The important issues to be considered when designing and selecting the appropriate gas cleaningmethods are as follows:

- High reduction efficiency of all harmful components

- Small waste water amount or no waste water - Minimal by-product streams- Products to be utilised or at least easy to dispose of - As separated product flows as possible, which contain high concentration of individual impurity

The gas cleaning methods applicable for each emission component and the reduction efficienciesachieved with these methods are shown in Table I.

Table I. Flue gas treatment methods and their reduction efficiencies.

Component Cleaning method EfficiencyParticulates • Electrostatic precipitator (ESP)

• Bag Filter 99%99.9%

Acid components:HCl, HF, SOx

• Dry system (bag filter): calcium hydroxide, activatedcarbon possible

• Semidry system (bag filter): suspension of water andcalcium hydroxide, activated carbon possible

• Multistage wet system: water, sodium hydroxide and/or calcium hydroxide

HCl 98%SO2 85%HCl 95-98%SO2 85-90%HCl 99%HF 95%SO2 >90%

NOx • SNCR: ammonia urea• SCR: ammonia• Activated carbon

40-65%60-75%80-90%40-60%

PCDD/DF • Activated carbon: fixed bed

so called Flugstrom• Catalytic oxidation in expanded SCR or separately

>99.9%

>99.5%97-99%

Mercury • Activated carbon systems• Use of additive (NaClO2, Na2S, Se, TMT, FeCl3)

98%90-99%

4.4.2 Sulphur dioxide

Sulphur content of a typical biomass fuel ranges from 0.01 to 0.10% by mass dry basis, and usuallySO2 emissions can be controlled to an acceptable level without any particular sulphur removal.

If additional removal is needed, limestone or other calcium based sorbent can be fed to the fluidised bed. Calcium oxide reacts with SO2, and the product is removed with fuel ash from the furnace. In CFBcombustion, 90% sulphur capture is normally achieved with 1.5-2 Ca/S ratio, while BFB combustion requires a

somewhat higher Ca/S ratio.

4.4.3 Nitrogen oxides

In FBC boilers the combustion temperature is relatively low, and no significant amounts of thermal NOx is formed. The total NOx emission is therefore dominated by fuel-bound nitrogen. Nitrogen content of most biomass fuels is typically low, 0.1 - 0.6% by mass dry basis, and the NOx emissions may be kept low enoughwith adequate staging of the combustion air. This naturally depends on the local regulation of the NOx

emissions. Typically, the values of 200 mg/Nm3 have been reached without any additional NOx reduction.

When further reduction of NOx emissions is required, ammonia injection at high temperature can beemployed, but in this case there is a possibility of slip of ammonia. Selective catalytic reduction (SCR) at lowtemperature may also be employed.



02001Ren9788 April 19978

The formation of N2O is more intensive in FBC boilers than in the combustion processes operating athigher temperatures. This is emphasised at low loads or when the combustion temperature is lowered for somereason, such as NOx reduction. With biomass fuels, the formation of N2O seems to be lower than with coal.

4.4.4 Particulates

Both baghouses and electrostatic precipitators (ESP) are used successfully to control particulateemissions from biomass fired FBCs. Resistance of the ash must be adequate, if ESP is used. In conventionalstoker-fired boilers, ESPs were preferred due to the risks of fire in the fabric filters. FBCs, however, have highcombustion efficiency and the potential for fires is considered to be low. Baghouses have certain advantages for HCl and dioxine/furan control, as HCl reacts with calcium oxide in the baghouse filter cake.

4.4.5 Carbon monoxide, hydrocarbons

Carbon monoxide and gaseous hydrocarbons are products of incomplete combustion. With the proper design of the combustor and control of the combustion process low CO and CxHy emissions are achieved. Eventhough the combustion temperature of a FBC boiler is relatively low, it is high enough to meet the emissionlimits, if good air/fuel mixing and adequate fuel residence time in the combustion zone is ensured.

4.4.6 Halogen, dioxin and furan emissionsSome biomass fuels contain little chlorine and require no controls. Certain biomass fuels, however,

may contain relatively high amounts of chlorine or fluorine. During combustion, chlorine is released as HCland fluorine as HF. Both HCl and HF are highly corrosive and environmentally harmful. Limestone injectedinto the combustor results in some control. HCl is mainly captured in the cooled section of the boiler and the baghouse, while HF is captured inside the furnace in hot conditions.

HCl can contribute to formation of small quantities of chlorinated organic compounds such as dioxinand furan. They can be controlled by assuring complete combustion of volatile organic compounds. This isdone by keeping the combustion temperature high enough for a sufficiently long time (typically 2 seconds isrequired). The cooling of the flue gases must also be carried out rapidly in order to avoid reformation. Coolingmay be difficult in practice.

4.4.7 Heavy metals

Volatile metals, such as Hg, As, Pb, Cd, Ni, V and Zn, are at least partly vaporised in the combustiontemperatures of FBCs. Vapours leaving the furnace are recondensed and enriched on the surfaces of ash particles. Control of the particulates serves therefore also control of the heavy metals. The only exception ismercury (Hg), which may not recondense at typical ESP or baghouse temperatures, and can leave the stack as avapour. Injection of additives, such as activated carbon, sodium sulphide, and limestone, have beendemonstrated for removing heavy metals, dioxine and chlorine in the flue gas stream.

5. CO-COMBUSTION OF BIOMASS AND COAL

5.1 General

Co-combustion of biomass and coal is an interesting option for many reasons. In the background, thereare the general reasons which favour the use of biomass fuels, such as regional aspects and the replacement of coal to decrease CO2 emissions. Co-combustion makes it also possible to use local biomass resources, whichmay be discontinuously available in varying quantities.

Biomass resources are dispersed with low energy density, which results in long transport distances andhigh transportation costs. Thus boilers fired with biomass only are small in size, typically below 50 MW th, andconsequently relatively expensive to construct and operate. The economy is improved when biomass is fired ina large scale unit with lower specific costs. The efficiency of a large scale power plant is often higher than thatof a small plant, so with the co-combustion the biomass fuel is converted into electricity with higher efficiencythan in a separate small scale boiler.

Co-combustion of biomass and coal can be implemented with different concepts. In the following, pulverised combustion, integrated fluidised bed or grate firing, and separate gasifier unit are discussed.



02001Ren9788 April 19979

Integrated fluidised bed or grate firing means that biomass is burnt at the bottom of the boiler in a fluidised bedor on a grate, and pulverised coal is fired higher in the furnace.

There are also different ways of integrating biomass combustion to coal combustion via the steamcycle, but these concepts have not been discussed in this report.

5.2 Pulverised combustion of biomass

Direct pulverised co-combustion of biomass and coal is possible with two concepts:- Mixing of biomass with coal prior to grinding- Separate line for pulverised biomass firing

Drying of biomass may reduce the capacity of the plant, or it may give limitation to the share of biomass to be used. Special unit for drying can be used, but it means higher costs.

The co-combustion applications are typically designed case by case. The design depends very much onthe characteristics of the biomass and the boiler. It is difficult to discuss co-combustion applications in general,

and so in the following certain individual cases are described.

5.2.1 Mixing of biomass with coal prior to grinding

Co-combustion of sewage sludge and coal, the Netherlands:In a Dutch power station, a total of 75,000 tonnes of sewage sludge per year, 6% (w/w) is intended to

be processed. In 1994, the Dutch Government declared that in a coal fired power plant co-combustion of 10% biomass (w/w) is allowed, and the limits of the air emission set by the Decree on Emission Requirements for Combustion Installation remain in effect. After a bench-scale test at KEMA in 1995, full scale experimentswere carried out, during which 1,500 tonnes of coal was replaced with 3,400 tonnes of dried sewage sludge.

Dried sewage sludge (moisture content approximately 10%) was delivered in briquettes and stored intoa small bunker. The briquettes disintegrated into fine dust during storage, compacting and transport to power

station. Consequently, dust and smell problems occurred during the unloading. From the small bunker thesludge was directly dosed onto the coal carrying conveyor and mixed with coal transported to the coal mills.During the experiments, no mechanical wear of the coal mills could be found.

No significant increase in slagging could be detected during frequent visual inspections. To evaluatethe impact of sewage sludge co-combustion on the environment, three distinctive aspects had to be considered:emissions to the (surface-)water, emissions to the air, and the properties of the solid waste residues. Co-firinghad no effect on waste water quality and the solid residues (fly ash, bottom ash and gypsum).

Although sewage sludge contains considerably more nitrogen (per GJ) than coal, higher NO x

emissions were not measured. Due to the comparatively high concentration of sulphur in sewage sludge, theSO2 concentration in the uncleaned flue gas increased distinctly. The flue gas desulphurisation removed morethan 90% of the SO2, and the limit of 200 mg/Nm3 was never exceeded. The emissions of Hg, HCl and HFincreased, but remained well below the legislator limit. By co-firing sewage sludge, no significant decrease of the efficiency in electricity generation could be determined, so about 43% of its energy content was utilised.This was possible because the material was dried.

Co-combustion of paper sludge and coal, the Netherlands:At a coal fired power plant, tests have been made with paper sludge with the aim to solve the disposal

problem for the paper industry and to reduce the CO2 emission. The aim is to burn, mixed with coal, about150,000 tonnes per year, which represents 10% (w/w) of the total fuel input. At the end of 1995, a test wasmade with approximately 2,500 tonnes of paper sludge (moisture content 50 %).

The paper sludge was dosed onto the coal conveyor belt, and the mix of coal/paper sludge was groundin the coal mills. In the co-combustion of 10% paper sludge with a high moisture content (50%) problems

arose. The desired temperature of the air leaving the coal mills could not be reached, and instability occurredwith some of the boiler controls. The instability resulted in a decrease of efficiency.



02001Ren9788 April 199710

The NOx emissions increased during the co-combustion of the paper sludge, but remained, like theemissions of dust and SO2, below the legislation limits. The emissions of heavy metals in the fly ash, bottomash and gypsum also remained within the usual ranges. By optimising the burning process, the NOx emissionscan be brought down to the usual value.

The tests have shown that drying of the paper sludge is necessary. This can be done with lowtemperature heat, which results in a higher efficiency as the external drying. A more accurate dosing system isalso necessary. With these precautions, it must be possible to achieve the same efficiency of the power plant asfired with 100% coal with no negative technical or environmental consequences.

5.2.2 Separate line for biomass preparation

Co-combustion of wood waste and coal, the Netherlands:In a coal fired power plant, 60,000 tonnes of waste and demolition wood will be used each year.

Special emphasis is placed on the processing of the powdered wood fuel (Fig. 5.1). When using wood, 45,000tonnes of coal averaging 4.5% (w/w) of the total annual fuel input will be substituted.

Wood chips (particle size 0-30 mm) are transported to the power plant in closed containers. Thecontainers are unloaded via an automated traverse and dumping system. In two grinders, the size of thematerial is reduced to 1-8 mm. Via chain conveyor, the wood is transported to two storage bins, which feed twomill units drying and reducing the material (d90 <800 µm, moisture content <8%). The wood particles are pneumatically conveyed to a silo adjacent to the boiler. Using four special wood burners with a capacity of 20MW each, sited below the lowest row of the existing coal burners, the wood is injected into the boiler.

The emission limits for the plant set by the provincial government have to be met. The power plant hasan efficiency of 38.5%. Although the energy costs of the logistics are about 3 MW, the net result is 16.5 MW,which is approximately 10 MW higher than in a waste incinerator.

Co-firing coal and straw at a 150 MWe power boiler, Denmark:The existing MIDTKRAFT 150 MW

e power plant (MKS 1) has been converted for the co-firing of

coal and straw and recommissioned by the end of 1995. The plant will be deployed for a two-year demonstration project, followed by routine operation at 15-20% straw input.

MKS 1 is a standard 150 MWe pulverised-coal power boiler. Main steam data are: 139 kg/s, 540/540°C, 143/41 bar. Straw storage, processing and feeding facilities of the total capacity of 19 tonnes/hr and theassociated control and auxiliary systems have been added, amounting to the total plant investment of 100MDKK.

Additional test equipment and instrumentation as well as sampling procedures will constitute the basisfor the demonstration programme, which will include short-term test series for plant tuning, followed by twolonger-term test series of 10% and 20% straw input (by energy).

The demonstration project will include the following tasks: coal reference operation, straw pre- processing plant performance, boiler plant overall performance, heat transfer distribution, superheater lifetimes,combustion process chemistry characterisation, burner optimisation, fuel and residue characterisation,emissions, boiler cold end corrosion, LoNOx firing and burner system development, semi-dry desulphurisation process, SCR catalysts, annual energy crops, technology and operating economy assessment.

5.3 Fluidised bed / grate firing incorporated in existing boiler

Fluidised bed technology can be applied to existing pulverised coal fired boilers by incorporating a bubbling fluidised bed in the boiler. The bottom part of the furnace is converted to operate as a fluidised bed,while the upper part of the furnace is used for pulverised firing (Fig. 5.2).

The share of the fluidised bed of the total thermal input varies case by case. The share may be up to100%, like at the Rauhalahti power plant, or remain relatively small. The size of the fluidised bed may be



02001Ren9788 April 199711

limited by many factors, such as biomass availability, physical size of the bed, structure of the boiler, heattransfer, ash slagging properties or increased volume of flue gases.

At large scale boilers the availability of the local biomass fuels may set an explicit and absolute limit tothe size of the fluidised bed, but sometimes other restrictions become determining. Cooling of the bed may be a

limiting factor. At normal fluidised bed combustion as much energy is released as to make some type of coolingnecessary in the bed. There are several ways to control bed temperature of the integrated fluidised bed:

- Fluidised bed may be designed to operate under reducing conditions, and the final combustion takes place above the bed. The bed temperature is controlled by air coefficient. Only part of the air neededfor combustion is fed to the bed as fluidising air and the size of the bed is smaller than at normalcombustion. Thus it is easier to integrate fluidised bed to the existing boiler.

- Heat exchangers can be used for cooling, but the risk of erosion of the heat exchanger tubes exists.The use of heat exchangers is relatively expensive, and it requires changes in the water-steam cycleof the boiler.

- A fluidised bed of low height may be used, in which case part of the combustion takes place abovethe bed, and the cooling effect by radiation has a great significance. In this solution there is arelatively high risk of the bed agglomeration.

- Flue gas recirculation can be used for the temperature control. Flue gas recirculation increases fluegas flow in the furnace and cross section of the fluidised bed. In most cases recirculation alonecannot be used for the temperature control.

When coal is replaced with biomass, the amount of the flue gases increases. This is due to two facts.Firstly, dry biomass produces more flue gases than coal for the same amount of energy. Secondly, biomass fuelsare often wet, which increases the flue gas volume and lowers the heating value.

The difference between the flue gas volume from biomass and coal combustion may be reduced bydrying the biomass prior to combustion. For instance, wood biomass with the moisture content of 45% producesabout 20% more flue gases than coal, with the same amount of energy produced. Combustion also requiresabout 7% more combustion air. If biomass is dried to the moisture content of 10%, the difference is reduced and biomass produces about 5% more flue gases than coal.

Alkali and chlorine compounds cause slagging problems in the heat transfer surfaces, particularly inthe coal fired boilers with high superheater temperatures. Fouling and consequent corrosion of the heat transfer surfaces restrict the share of biomass that can be used. On the other hand, alkalis and chlorine are blended withcoal ash, which may lessen the problem. The part of biomass that can be used depends on the type and thealkali content of the biomass fuel. Due to mixing, the use of ash may be more difficult and cause additionalcosts in co-combustion.

There is not much data available about the effects of the integration on the SOx and NOx emissions of the boiler. The use of biomass in a pulverised coal fired boiler may decrease efficiency of the selective catalytic NOx reduction. It has been noticed that the performance of the catalyst decreases faster, if biomass is fired,instead of coal. The efficiency of the catalyst also settles to a lower level with biomass than with coal.

Integration of a fluidised bed to an existing pulverised coal fired boiler is relatively cheap. This is thecase when the fluidised bed can easily be integrated to the existing boiler and no extensive changes are made tothe heat transfer surfaces or to the flue gas channels.

The technique of the integration of the fluidised bed to an existing boiler has been proved in pulp and paper industry, where several boilers have been modified for fluidised bed combustion. The new items comprisethe technique applied to the pulverised coal fired boilers which have relatively small flue gas volumes in proportion to power, and there is the requirement of the simultaneous combustion of biomass and coal.

5.4 Separate combustor/gasifier unit

In case there is not enough room to modify the bottom part of the existing coal fired boiler to anintegrated fluidised bed, biomass can be burnt in a separate fluidised bed boiler. The biomass boiler operates



02001Ren9788 April 199712

parallelly with the coal fired boiler, and the flue gases of the biomass boiler are conducted to the existing boiler (Fig. 5.3). Cooling of the fluidised bed and supply of the flue gases to the coal fired boiler must be arranged.This arrangement is probably more expensive than the integration of the fluidised bed at its cheapest.

Biomass fuels are highly reactive, which makes efficient gasification possible with relatively simple

and low-cost gasification technologies. This enables biomass fuel to be gasified in a separate gasifier and theuse of the product as fuel in the pulverised coal fired boiler.

When biomass fuel is gasified in a separate reactor, the supply and the combustion of the product gasin the coal fired boiler must be arranged. Otherwise the gasifier can operate as a separate unit with its own air and fuel feeding systems.

There is quite a lot of experience about the atmospheric gasification of biomass fuels, even though thegasification technology has not been established yet. Technology has been used to gasify industrial wood wastesin order to replace fossil fuels in the industrial processes.

The mixing of biomass and coal ashes can be avoided with a separate gasifier unit. In order to separate

the ashes completely, there must be a gas cleaning device between the gasifier and the boiler, if fluidised bedgasification is used. This device can simply be a cyclone. If fixed bed gasification is used, the ashes can beseparated without a separate cleaning device.

Removal of the ash by a cyclone in a fluidised bed gasifier or the use of a fixed bed gasifier withoutany cleaning device lowers the risk of fouling and corrosion of the heat transfer surfaces, but is not necessarilyenough to prevent fouling or corrosion completely. The total avoidance of the alkali and halogen compounds inthe boiler requires the removal of the vaporised compounds and aerosols. This means that the product gas must be cleaned with some kind of alkali and halogen condenser and scrubber prior to combustion. Cooling of thegas may lead to fouling and corrosion problems. The scrubber water also needs to be treated.

Combustion of the gas produced by air gasification of biomass may cause certain problems. The gashas a low heating value, and it may contain particulates and tar. Combustion of the gas may require the use of supporting fuel. Ammonia and tars in the product gas may increase NOx formation in the boiler.

The use of a separate gasifier unit in the co-combustion of biomass and coal is relatively expensive. Itmay compete with the integrated fluidised bed, if the integration of the fluidised bed is difficult or if there isgreat importance in keeping the ashes separate. If complete line of gas cleaning is to be applied, the economy is poor.

The two-step bio-boiler concept, Denmark:The project involves combustion in separate boilers with a straw-fired Benson boiler and first

superheater combined with a wood chip-fired final superheater (Fig. 5.4). The water/steam cycle is connectedin parallel to the existing coal-fired 630 MWe boiler, unit 3 (EV3). On December 15, 1994 ELSAM´s Board of Directors approved the project, which will take 33 months to complete. The project includes the design,

purchase and commissioning of the new boiler concept. The project budget amounts to about DKK 400 million.

In this installation the water/steam cycle is connected in parallel to the turbine of the existing coal-fired 630 MWe boiler unit. The first step of the bio-boiler concept is a straw-fired Benson boiler for evaporatingand first superheating, and the second step is a wood chip-fired tower boiler as final superheater. The outletsteam temperature of the straw boiler will be 470 °C and will be superheated up to 542 °C in the wood chip-superheater. By separating the combustion of straw and wood chips and the resulting flue gases into separate boilers, the high-temperature corrosion deriving from the high chloride content in the straw is expected to beavoided, provided the steam outlet temperature of the straw boiler is kept at or below 470 °C.

The feed water is taken from EV3´s feedwater and led to a new feedwater tank. Via a well-insulated450 m pipeline, the live steam is added to EV3´s high-pressure live steam before the HP turbine. The flue gases

from the boilers are mixed (at lower temperature) before entering the air preheater. Both boilers will beequipped with vibration grates. The residues are kept separated to improve utilisation.



02001Ren9788 April 199713

The capacity of the two-step bio-boiler concept is designed on the basis of an annual biomassconsumption of 120,000 tonnes of straw and 30,000 tonnes of wood chips. The biomass is primarily burnedwhen EV3 is operating between full load and 45% load, which corresponds to approx. 6,000 full load hoursannually for the straw/wood chip-fired boiler.

The main data for the straw/wood chip-fired boiler at 100 % load are:Live steam data 542 OC, 200 bar Biofuel input (85 % straw and 15 % wood chips) 95.50 MJ/s(120,000 tonnes of straw and 30,000 tonnes of wood chips yearly)Power output (ratio of EV3´s 630 MW turbine) 40 MWe

Efficiency 41,9%Amount of coal saved (H1 = 24.7 MJ/kg) 80,000 tonnes/year Reduction in CO2 emission (coal substitution) 190,000 tonnes/year Reduction in SO2 emission (coal substitution, 1% S in coal) 1,600 tonnes/year

6. GASIFICATION

6.1 Background of gasification

Commercially, biomass gasification is in use for replacing oil and natural gas fired boilers or other furnaces. The applications are based on the atmospheric pressure gasification, and the economies are often based on the replacement of expensive fuel in special situations or avoiding some environmental investments.

Typically this kind of application is a small 2 - 10 MWth central heating plant, in which wood chipsare gasified in a fixed bed gasifier and the product gas is used as fuel in a standard oil fired boiler. Theadvantage of the connection is that the investment cost of the plant is low, and the fuel is cheap and practicallysulphur free when compared with oil. In a somewhat larger scale (over 10 MWth), gasification has been appliedto produce fuel for lime kilns in kraft pulp mills from the wood wastes of the pulp and paper industry. Theseapplications are based on the circulating fluidised bed technology.

Atmospheric gasification of biomass has also been applied to the gasification together with a dieselengine. Biomass has been gasified in order to produce fuel gas for the diesel engine. The gasificationtechnology used is based on either fixed bed or fluidised bed technology. Usually the development work hasencountered difficulties with the product gas clean up. Typically, tars of the product gas have condensed and blocked the equipment prior to the engine during cooling and compression, which is required in order to obtaina sufficiently high feeding rate of the fuel gas into the engine. Problems have also been experienced withachieving a sufficiently complete combustion of the gas in the engine. Gasification of biomass coupled with adiesel engine has been developed by Omnifuel (Canada), Foster Wheeler (earlier Ahlstrom Pyropower,Finland), and TPS Termiska Processer AB (formerly an operating unit of Studsvik AB, Sweden). Probably themost advanced technology was developed by TPS, in which the biomass is gasified in a circulating fluidised bedreactor and the tars are cracked in another reactor before conducting the gas into the engine or the gas turbine

(Fig. 6.1).

The development work of the pressurised gasification is mainly based on the technologies of theatmospheric gasification. However, some technologies originate from the processes developed for the syngas production.

The purpose of the pressurised gasification of biomass is to produce fuel gas for the gas turbine, after the product gas has gone through a cleaning process. This makes it possible to use the gas turbine cycle, whichoffers several advantages in power production. The gas turbine cycle can be integrated to the steam cycle(Integrated Gasification Combined Cycle, IGCC), or, with the use of the steam injected gas turbine (STIG), thesteam turbine can be omitted or at least the size of the steam cycle can be considerably decreased and yet the plant operational economy is not lowered (Fig. 6.2). Gasification can be carried out by either oxygen or air, but both the properties of biomass and the probable size of a biomass fired plant favour air gasification.



02001Ren9788 April 199714

In condensing power production, the combined cycle processes give a higher efficiency whencompared with conventional plants. In regions, where the price of electric power is high and the availability of biomass is secured, and of relatively large scale, it is possible to apply the gasification technique with biomassin the production of condensing power. However, in comparison with the coal-fired plants, the size of the biomass plants is relatively small.

When applying IGCC/STIG technology to combined heat and power production, (CHP) the power toheat ratio can be increased significantly, from a typical value of 0.5 to a value of 0.8 - 1.4. Increase in therelative power supply in industrial power plants will be even greater when transferring to the gasificationtechnique.

Gasification is usually carried out at such a pressure that the fuel gas can be fed directly into thecombustion chamber of the gas turbine after the cleaning process and a possible cooling stage, withoutadditional compression. An exception is made at the processes, in which the gasification is carried out atatmospheric pressure, and the fuel gas is compressed into the combustion chamber of the gas turbine.

A separate group of ideas is formed in development concepts in which a small part of biomass is

gasified together with other fuels, e.g. oil or coal.

6.2 Technical description

Below, only the biomass gasification processes are discussed, which produce fuel gas for the gasturbine. Therefore, the pyrolysis processes and in general processes based on the atmospheric gasification arenot considered here. The applications of gasification coupled with a diesel engine are also excluded.

Generally, a biomass-fired gasification power plant will be of a modest size. This is due to the limitedlocal biomass resources, and, on the other hand, this kind of plant will often be constructed as a CHP plantconnected to a heat load with limited capacity. The small size of the plant favours certain technical solutions,which include:

- Air-blown gasification instead of oxygen- Use of simple gasification technologies (either bubbling or circulating fluidised bed, for example)- Use of a simple dry gas cleaning technology (not available yet)

The use of biomass in an IGCC process can be divided into fuel preparation, gasification, gas cleaning,gas turbine, and steam cycle.

6.2.1 Fuel preparation

With biomass, the fuel preparation is, compared with the use of coal, more emphasised andcomplicated. Depending on the fuel type delivered to the power plant, the fuel has to be ground and sieved.Fuel of high moisture content has to be dried before gasification, and fuel feeding into high pressure is moredifficult, due to the large volume flow and material properties.

Low-rank feedstock, such as biomass, normally has a high initial moisture content, which leads to theneed to dry the fuel prior to gasification. The moisture content of wood biomass, for example, is of the order of 40 - 60%, and it has to be dried to the final moisture of about 15 - 20% prior to the gasifier in order to reachgood gasification result and proper gas quality.

The drying of biomass can be implemented using different process concepts. Usually fuel of highmoisture content, when used in a power plant, is dried using flue gases as energy source in a mill dryer, flashdryer or rotary drum dryer. Recently, steam drying applications have also been developed and used for drying of materials such as peat and bark, and brown coal. The advantage of steam drying is the possibility to recover part of the energy used for drying to the process by condensing the evaporated steam in a heat exchanger.Steam atmosphere is also inert, and there is no such risk of fire as in case of using flue gases as heat source.Steam dryers can be indirect tube dryers, fluidised beds, and flash dryers.



02001Ren9788 April 199715

Fuel feeding into high pressure atmosphere is usually implemented using the lock-hopper technology.In this system, one or two parallel hoppers are periodically pressurised and depressurised to provide material tothe pressurised feeding hopper. From this point, feeding to the gasifier is usually implemented with screws. For pressurisation of the hoppers, nitrogen or dried low oxygen content flue gas may be used. The need of inertisation is due to the high risk of fire with biomass fuels. The drawbacks of the lock-hopper systems are,

particularly in case of biomass, their complexity and high inert gas consumption, due to the high volume flowof the fuel. This also leads to high investment costs of the whole system.

Another technology possibly applicable for the fuel pressurisation is the piston feeding technology.Various types of piston feeders, often based on the technology developed for concrete pumping, have also beentested for biomass feedstocks. The advantages of such feeders are lower investment costs and smaller inert gasconsumption.

6.2.2 Gasifier

Usually biomass is gasified in fluidised bed reactors using air as a gasifying agent. Most biomass fuels, particularly those derived from wood, produce little char residue, the structure of which is porous and thereactivity high. The ash content is typically low. These characteristics make the gasification of biomass

relatively easy. Therefore, the most commonly used fluidised bed gasification technology is well suited for thegasification of biomass, and a high carbon conversion, more than 98%, can be achieved. Both the bubbling andthe circulating fluidised bed technology has been applied to the fluidised bed gasification. In the bubblingfluidised bed concepts, the bulk of the entrained fines is usually also recirculated by cyclones into the bed.

In a fluidised bed gasifier, the temperature is kept below the melting point of ash, in other words below850 - 950 °C. The ash melting point of some biomass fuels, such as straw and willow, may be significantlylower, and the gasification temperature should be below 850 °C. The use of straw alone is not possible; with50% coal, straw has been successfully tested. In a bubbling fuidised bed gasifier, the temperature of the bed can be lower than the temperature of the freeboard. In a circulating fluidised bed gasifier, the temperaturedistribution is even throughout the reactor. Some steam can be used as additional gasification agent in order toincrease the amount of hydrogen, but usually the hydrogen and moisture content of the biomass is so high thatthe amount of steam remains small.

Both the sufficiently high temperature required by the gasification reactions and the sufficiently highheating value of the fuel gas required by the gas turbine can be achieved by using air as gasification agent. Thegasification air is taken from the compressor of the gas turbine and compressed further by a booster compressor to the pressure determined by the gasifier. The power consumption of the booster compressor can be reduced bycooling the air before the compression.

The gasifier is of uncooled, usually refractory lined, design. Sand, limestone or dolomite can be usedas additional bed material. The purpose of the additional bed material is to maintain sufficient bed inventorywhen using fuels with low ash content, and, in some cases, to act as a catalyst or a sorbent

The heating value of the gas produced with the fluidised bed gasification is relatively low. Typically

the heating value of the gas is of the order of 5 MJ/m3n (LHV). The product gas also contains impurities: heavyhydrocarbons, tars, which are pyrolysis products of the biomass, which have not had the time and high enoughtemperatures to decompose in the upper part of the gasifier. The gas also contains small amounts of ammonia,hydrogen cyanide, alkalis and dust. Typical gas compositions of various fuels from a 400 kWth pressurised bubbling fluidised bed gasification test unit are shown in Table II. Because of the relatively high heat losses of the small test unit, the product gas composition of a larger gasifier may be somewhat different.



02001Ren9788 April 199716

Table II. Product gas compositions of different feedstocks from a 400 kWth pressurised bubblingfluidised bed gasification test unit.

Feedstock Saw dust Peat Brown Polish coal

Air to fuel ratio k /k -daf 2.09 2.81 3.61 5.05

Steam to fuel ratio, kg/kg-daf 0.16 0.18 0.20 0.56

Limestone feed, kg/kg 0.03 - - 0.13

Pressure, MPa 0.40 0.50 0.50 0.50

Bed temperature, °C 820 820 825 975

Freeboard temperature, °C 1015 880 910 990

Carbon conversion, wt-% to dry gas to dry gas + tars

95.298.0

92.293.3

95.996.2

80.680.7

Gas com osition vol-%

CO 14.0 11.0 16.4 10.2

CO2 12.1 12.8 10.0 10.6

H2 10.2 10.9 12.0 8.9

CH4 3.6 2.3 1.1 0.6

C2 hydrocarbons 0.2 0.2 <0.1 <0.1

NH3 0.04 0.50 0.19 0.15

H2O 13.0 13.2 7.3 12.3

N2 +Ar 46.9 49.1 53.0 57.2

Tars, g/m3n (wet gas) 5.0 1.9 0.6 0.2

6.2.3 Gas cleaning

The product gas of a fluidised bed gasifier contains several impurities: nitrogen and sulphur compounds, alkali metals, tars, and particulates. The gas must be cleaned from these impurities in order tomeet the environmental emission limits and on the other hand in order to protect the gas turbine. It isadvantageous to carry out the gas clean-up at a high temperature, primarily because of higher processefficiency. The hot gas dust removal is favoured also by the low sulphur content of biomass, as there isnormally no need for sulphur removal. The condensation of the tars contained in the product gas can also beavoided by keeping the temperature of the gas sufficiently high.

The sulphur content of biomass is typically very low. Therefore, the environmental emission limits areusually met without any sulphur removal. If the fuel, however, contains considerable amounts of sulphur, mostof the released fuel sulphur is converted into hydrogen sulphide (H2S) with smaller amounts of carbonylsulphide (COS) and other sulphur compounds, the bulk of which can be removed in the fluidised bed gasifier by

using calcium-based sorbents. The calcium-based sulphur removal in gasification is thermodynamicallylimited, and, in an extreme case an additional cleaning step may be needed to remove the rest of the sulphur.

During the gasification, a significant part of the fuel nitrogen may be converted into ammonia (NH3),hydrogen cyanide (HCN), and other nitrogen compounds; ammonia being typically the dominant compound.These gas impurities may go through the gas clean-up systems and create NOx in the gas turbine. The fate of fuel nitrogen in gasification depends both on the gasification conditions and on the way nitrogen is bound inthe feedstock. With the high volatile fuels, such as biomass, the conversion of the fuel nitrogen to ammonia hasa tendency to be very high. Some correlations have been found between the freeboard temperature and theconversion of fuel nitrogen to ammonia. When the temperature is increased, the conversion is usually slightlydecreased. Catalytic high-temperature gas cleaning, yet under development, is one alternative to removeammonia and other nitrogen compounds from the gas before burning it in the gas turbine. Certain catalyticallyeffective materials, such as dolomites, have been tested as bed additive in fluidised bed gasifiers, but much better results have been achieved by using a separate catalytic gas cleaning reactor.



02001Ren9788 April 199717

The product gas contains trace amounts of gaseous alkali metals, which may pass through the particulate removal devices. The alkali metals are thought to be the main cause of the high temperaturecorrosion of the gas turbine blades. The higher the inlet temperature is, the more sensitive the blades are tocorrosion. The current industrial gas turbine specification limit for the alkali metal compounds is of the order of 0.1 ppm by weight. According to the equilibrium calculation, gas cooling below 500 - 600 °C before the

particulate removal would decrease the concentrations close to the specification limit due to the condensation of alkali metals on the surfaces of particles to be removed. Certain experimental research supports thisassumption, but it must be remembered that several variables, such as gasification temperature, sorbentaddition, the effectiveness of fines recycling etc., may considerably affect the release and removal of alkalimetals.

When considering the particulate removal from the product gas at high temperature and high pressure,the ceramic filter elements provide a promising alternative. A typical dust value of less than 5 mg/m 3n isexpected after the ceramic filter. The use of cyclones is problematic, because in the gasification a lot of smallcarbon containing particles are elutriated from the gasifier and these particles are difficult to remove bycyclones. The product gas is typically cooled after the gasifier to a temperature of 350 °C, because of the gasturbine requirements. At these temperatures, the ceramic filter elements seem to be a more reliable solution

than at the higher temperatures, at the temperature of 800 - 900 °C of the pressurised fluidised bed combustionapplications, for example.

In the biomass gasification, one of the major problems is the formation of tars. Most of the tar components are not problematic, if the hot gas clean-up is applied. However, the thermal decomposition of pyrolysis products leads to a formation of high molecular weight polyaromatic compounds and soot, and thesegas impurities may cause blinding of the ceramic filters. During the gasification, the cracking of tars is promoted by the high gasification temperature and the catalytic effects of the bed material. A separate tar removal unit may also be connected to the process, particularly if the product gas is to be cooled. Developmentof the equipment is ongoing.

6.2.4 Gas turbine

When applying a process based on the use of biomass, the gas turbine must be able to burn lowcalorific gas. Combustion of low calorific gas in commercially available gas turbines requires certainmodifications in the gas turbine hardware. The gas turbine has to be equipped with modified combustionchambers to burn the gas efficiently and with low levels of nitrogen oxide emission. The density of the fuel gasis relatively low, which means that the volume flow of the gas is high. The fluctuation of the heating value of the fuel gas may cause problems. The air needed for gasification has to be extracted from the gas turbine after the compressor. The pressure and temperature of the gasification air are adjusted by a booster compressor/heatexchanger system to the appropriate level.

The amount of dust and alkalis a gas turbine can accept is very low. The nitrogen compounds of thefuel gas, such as ammonia, are to certain extent converted into elementary nitrogen, and to certain extentconverted into nitrogen oxides during combustion in the gas turbine.

The selection of commercial gas turbines which meet the criteria for the combustion of low calorificgas is fairly limited, particularly in the size class suitable for the biomass applications. The gas turbinesuppliers do not seem to be particularly interested in developing gas turbines for low calorific gas.

6.2.5 Steam cycle

The steam cycle consists mainly of commercial components, such as conventional combined cycle plant. The main difference is the product gas cooler, typically operating as an evaporator coupled to a heatrecovery steam generator.

Because of the small size, it is advantageous to keep a biomass plant as simple as possible. One way of simplifying the process is to omit the steam cycle and to accomplish the plant with a steam injected gas turbine.



02001Ren9788 April 199718

6.3 Technologies and projects

6.3.1 Technologies

Foster Wheeler:Foster Wheeler (earlier Ahlstrom Pyropower), is developing pressurised circulating fluidised bed

(CFB) gasification for biomass applications. The pressurised CFB gasification is a development of theatmospheric CFB gasification developed by Ahlstrom in the early 1980s for fuelling lime kilns in kraft pulpmills. The know-how of the atmospheric and pressurised Pyroflow CFB combustion has also been used in thedevelopment work.

The fuel is dried in an integrated flue gas drier to a moisture content of 10 - 20%. The size distributionis typically between 30 and 50 mm. The fuel is pressurised to a value, which is dependent on the gas turbinerequirement, and fed into the gasifier, which is an air-blown CFB gasifier with an operating temperature of 950- 1000 °C. The formation of tars is minimised by thermal cracking and the catalytic effect of the bed material.The product gas is cooled to 350-400 °C in a gas cooler in which steam is generated. After the cooling, the gasis cleaned in a hot gas filter where particulates are removed with ceramic filters. Ash is removed from the

process both via the bottom of the gasifier and via the hot gas filter. The fuel gas is low calorific gas with alower heating value of about 5 MJ/m3n.

Renugas:Institute of Gas Technology, USA, has developed a Renugas gasification process suitable for the

gasification of biomass. The process development unit has been tested with maple pulpwood chips, whole treechips, and a mixture of bark and pulp mill waste sludge, for example. The unit is not cooled, pressurisedfluidised bed steam and oxygen-blown biomass gasification system with a nominal design feed rate of 12 t/d.

U-Gas:Carbona Inc. (earlier Enviropower Inc.), is developing an IGCC process for various solid fuels,

including biomass. The concept incorporates pressurised fluidised bed gasification of various solids fuels

employing the U-Gas gasifier developed by the Institute of Gas Technology. The process applies air-blowngasification and hot gas clean-up.

In the U-Gas gasification system, biomass is gasified using an air-blown fluidised bed. Air gasificationrequires the biomass to be dried to the moisture content of 15 - 20% to generate gas of adequately high heatingvalue. The dried fuel is fed into the gasifier using lock-hoppers. Since the ash content of biomass is low, aninert bed material such as sand or dolomite is used. Almost all the ash is carried over from the gasifier with the product gas, the bulk of which is captured with the cyclone and returned to the gasifier.

The gasifier operates at about 950 °C and generates low calorific value gas of about 5 - 6 MJ/kg LHV.The gasifier pressure is within the range of 20 to 25 bar determined by the gas turbine requirement. The product gas leaving the gasifier is cooled in a gas cooler to 400 - 550 °C. Tar destruction occurs mainly in thegasifier at high temperature, using dolomite and maintaining efficient circulation in the bed and recirculationof entrained fines. The dust removal device before the gas turbine is the high temperature/high pressure filter.

TPS Termiska Prosesser AB:TPS Termiska Prosesser AB is a small independent Swedish company, formerly an operating unit of

Studsvik AB.

The TPS gasification is based on the circulating fluidised bed (CFB) technology. The process involvesgasification at around 1.8 bar followed by a series of gas conditioning steps prior to the gas turbine. These stepsinclude cracking of the tars to non-condensable gases in a fluidised bed dolomite-filled reactor, cooling, baghouse filtration at 180 °C, scrubbing, compression and reheating.

FERCO/Battelle:



02001Ren9788 April 199719

The FERCO/Battelle technology for biomass gasification was developed by Battelle at the BattelleColumbus Laboratories (BCL) in the 1980s. In 1992, Future Energy Resources Corporation (FERCO) acquired patents for the technology.

The BCL/FERCO process utilises circulating fluidised bed reactors to produce medium calorific product gas. The process uses two physically separate reactors. One reactor is a gasifier in which biomass is

converted into medium calorific gas and residual char. The other reactor is a combustor that burns the residualchar to provide heat for gasification. Heat transfer between reactors is accomplished by circulating sand between the gasifier and the combustor.

Others:Gasification processes, which initially have been developed for coal or brown coal applications, are

being adapted to biomass or co-gasification applications. These processes are developed by Lurgi and NOELL,for example.

6.3.2 Projects and demonstration plants

Värnamo demonstration plant, Sweden:The Värnamo demonstration plant is the world's first biomass power plant incorporating pressurised

IGCC technology. The plant located in central Sweden is owned by Sydkraft AB, and the CFB gasificationtechnology is delivered by Bioflow (a joint venture of Foster Wheeler and Sydkraft). The construction of the plant began in September 1991, and the commissioning started at the beginning of 1993. A research programme spanning a period of several years is now under way.

The plant uses wood waste as fuel and generates 6 MW of electricity and 9 MW of heat for the districtheating system. The fuel delivered to the site is crushed and dried in an external fuel preparation facilitydesigned to handle forest and sawmill residues. The feeding of the biomass into the gasifier operating at 24 bar / 950 - 1000 °C is accomplished with lock-hopper systems as well as the feeding of bed material. The productgas heating value is about 5 MJ/m3n. The gas cooler lowers the temperature of the gas to approximately 350 °C.The cooler utilises water as cooling medium. The hot gas clean-up system comprises ceramic candle filters provided by Schumacher. The Ruston Typhoon gas turbine supplied by European Gas Turbines Ltd. generates4.1 MWe. The exhaust gas temperature from the turbine is slightly less than 500 °C, for which reason the livesteam values of 40 bar / 470 °C were selected.

There have been several problems with the commissioning of the plant. In autumn 1995, the plant wasoperated for short periods with the gas turbine and fuel gas. During the operation of the gas turbine there wasan external fire with oil outside the gas turbine. The gas turbine was sent back to EGT for maintenance, and itwas sent back in January 1996. In 1996, the gas turbine was operated on product gas for some 200 hours.

The Pacific International Center for High Technology Research (PICHTR) Project, USA:The U.S. Department of Energy (DOE) and the State of Hawaii have joined with PICHTR in a co-

operative project. The object is to scale up the process development unit of Institute of Gas Technology (IGT)Renugas pressurised air/oxygen gasifier to an engineering development unit operating at 10 - 20 bar, using bagasse and wood as feed.

The first phase, which is under way now, consists of design, construction, and preliminary operation of the gasifier to generate hot, unprocessed gas. The gasifier operates with either air or oxygen at pressures up to22 bar, at typical operating temperatures of 850 - 900 °C. In Phase 1, the gasifier will be operated for about four months at a feed rate of 45 t/d at a maximum pressure of 10 bar. In Phase 2, a hot gas clean-up unit and gasturbine will be added to the system to generate 3 - 5 MW e. The gasifier feed rate will be 90 t/d, and the systemwill operate at pressures up to 22 bar. In Phase 3, the system will be operated in an oxygen-blown mode to produce clean syngas for methanol synthesis, in addition to producing electricity.

The World Bank Global Environment Facility (GEF) Project, Brazil:The project is funded by the World Bank's Global Environment Facility and it has several phases. The

first phase, which included preliminary investigations of various technologies, was completed in March 1992,

and the project team chose to arrange a competition between two designs: a low-pressure option with TPSTermiska Processer AB and a high-pressure option with Bioflow. Both designs are based on the GeneralElectric LM2500 aeroderivative gas turbine.



02001Ren9788 April 199720

In the second phase, two independent project teams worked in parallel to develop distinct technology packages. The design studies of both companies were reviewed by project representatives, and the TPS low- pressure gasification technology was selected to be processed as the GEF scale-up. In the third phase, the power plant will be constructed in Northeast Brazil.

The Burlington, Vermont Project, USA:The Burlington, Vermont Project is based on the FERCO/BCL gasification process. The object of the

project is to demonstrate in a commercial scale that the process will work over a broad range of biomassfeedstocks. The plant is designed to process a minimum of 8 dry tonnes of biomass per hour.

The plant will operate primarily on wood waste (bark, saw dust and whole tree chips), but the feedingsystem is oversized to allow test operation on other clean biomass fuels such as bagasse and switchgrass. The product gas is combusted in the existing boiler, and the hot flue gases from the char combustor are ducted to the boiler. A gas turbine and heat recovery boiler can be added to the process later.

The engineering of the gasification plant is complete. Major equipment will arrive on site in April

1996, and the start-up activities will be started in late 1996.

Oulu peat gasification plant, Finland:Kemira Oy has built a peat-fired demonstration ammonia plant based on HTW (high-temperature-

Winkler) gasification at Oulu, Finland. The HTW gasification technology could most probably be adopted tothe gasification of biomass

7. ECONOMICS AND FUTURE OUTLOOK

7.1 Economics

In the power production, biomass competes with other ways of producing electricity and with other

fuels. Biomass fuels coming from various sources have very unequal ability to compete, and the competitionsituation varies in each country and region.

The ability of biomass to be successful in competition is at its best in the forest industry, where biomass is locally available in large quantities, and it is collected in the mill area. The mill consumes a lot of energy and there is no alternative usage for biomass. The value of alternative usages, except the conversion intoenergy, may be even negative. In these cases, it is economically viable to convert industrial wood waste,consisting of bark, waste wood chips, saw dust and various sludges, into energy in local CHP plants. Energy production may be profitable, even though biomass would contain harmful impurities and additional flue gastreatment equipment would be needed. In Finland, for example over 10% of all electricity is produced fromwood and wood wastes from the forest industry, with black liquor included.

The size of a CHP plant is usually limited by the volume of the heat load, and even small CHP plantsmay be profitable, since major part of the energy content of the fuel can be sold in the form of power and heat.The economies are not capable of accepting long-distance transportations of biomass. All in all, thecircumstances favour the use of biomass in small CHP plants, or as additive fuel in large CHP or condensing power plants. Without the advantage of the size limitation of CHP plants, biomass, limited to the small unitsize, has difficulties in competing with fossil fuels in large power plants.

Most biomass fuels are very dispersed, and the collection and transportation, and in certain cases alsothe production, are relatively expensive. In addition, some biomass fuels are difficult to handle and burn, andadditional investments are required at the plant. Thus, the competitiveness of biomass without any support is poor, when compared with fossil fuels.

The quantity of biomass to be collected in one location with reasonable transportation distances is

relatively small, and so the advantages of a large scale plant (lower specific investment cost and higher efficiency) favour fossil fuels. The disadvantage of the small size can be compensated by using biomass as



02001Ren9788 April 199721

additional fuel in pulverised coal fired boilers; or by building multifuel boilers, such as fluidised bed boilers; or by using biomass in CHP plants, where heat load restricts the size of the plant.

The ability to compete of different biomass fuels in CHP or condensing power production is roughly asfollows:

Industrial wood wastes, such as bark, saw dust, waste wood chips and black liquor:- Competitiveness is high, if large amounts are centralised to be available in one place.

Sludges from the forest industry:- Competitiveness is moderate, if sludge can be used as fuel without additional flue gas

treatment equipment, or if the charge of disposal is high.Forest residues:

- Competitiveness is poor without support measures; technical development work is beingcarried out in order to reduce the harvesting costs.

Sludges from the food industry:- Profitability depends on the disposal fee.

Straw:- Competitiveness is questionable without support measures.

Energy crops:- Competitiveness is questionable without support measures, cultivation may be profitablewith the present agricultural subsidies.

Sewage sludges:- Profitability depends on the disposal fee.

The competitiveness of biomass fuels for power production has been promoted by imposing a tax oncompeting fuels (Sweden, Finland), with subsidies (Denmark), or with ordering the electricity distributor to payan increased price for the electricity produced from biomass (Italy). With these measures, the power or CHP production has been advanced also beyond the forest industry.

Technical development work is being done in different areas in order to improve the competitivenessof biomass as fuel. The development trends are:

- Integration of harvesting of forest residues to harvesting of commercial wood- Harvesting and handling technology of straw- Cultivation technology of energy crops- Handling technology of biomass- Combustion technology of high alkali biomass (mostly FBC technology)- Co-combustion of biomass and coal- Gasification, gasifier coupled with diesel engine, and gas turbine technologies- Flue gas treatment technology

The costs of various biomass fuels at the plant in Denmark predicted for the year 2000 in today’smoney is shown in Table III.

Table III. The costs of biomass fuels predicted for the year 2000 (Denmark).ECU/GJ Min Most likely Max

Straw 3.0 4.0 8.9Wood 4.2 4.6 7.0Energy crops 4.2 5.6 7.0

Approximate split of the costs on the farmers side for straw in Denmark:Collecting and compressing 36%Transport to store (on the field) 11%Store costs 25%Transport to power station 18%Farmers profit 10%

Total 100%



02001Ren9788 April 199722

As the energy density of biomass is lower than the one of fossil fuels, transportation costs are acomparatively greater share of the final fuel cost. This is an important incentive for the use of small scaleapplications, although this in turn brings about low efficiencies and high specific investment costs.

In Finland, the price level of 2 - 2.5 ECU/GJ for biomass fuels is targeted.

In Finland, the fluidised bed technology has been developed for biomass and peat. The specificinvestment costs of several small scale CHP plants built in the 1990s are shown in Table IV. These plants donot include any flue gas cleaning equipment.

Table IV. New small scale CHP plants in Finland in the 1990s.

Plant Takeover Capacity Steam Type of Investment power/heat values boiler cost

MW/MW oC/bar million ECUPieksämäki 1992 9/25 510/60 BFBC 9.5Kankaanpää 1992 6/16 510/60 BFBC 8.0

Kuhmo 1992 5/13 490/81 CFBC 12.3*

Ylivieska 1993 5/15 510/60 BFBC 8.7Kuusamo 1993 6/17 510/60 BFBC 8.0

Lieksa 1994 8/22 510/61 CFBC 11.3*

* demonstration of new boiler technologies

The price of electricity and the investment cost of the Pieksämäki CHP plant, and the correspondingvalues of a small scale plant designed previously at the same location are shown in Table V. The progress dueto the technical development and learning can be seen from the figures.

Table V. Cost estimates of the Pieksämäki power plant (cost level=year 1991).

Year of estimation 1979 1987 1989 1990 1991Power/Heat, MW/MW 10/23 15/35 10/21 7/23 9/25

Total costs, million ECU 33 31 25 11 10Specific costs, MECU/MWe 3.3 2.1 2.5 1.6 1.1Power, ECU/MWh 53 33 38 20 15

7.2 Future outlook

Among the various technologies, the fluidised bed technology and steam cycle will most certainly become more common. The fluidised bed technology requires still a good deal of development work, particularly as far as the high alkali and high chlorine fuels are concerned. The capital cost of a CFB boiler ishigher than that of a BFB boiler, but CFB boiler offers higher combustion efficiency and more efficient sulphur capture, due to better mixing and recycling of the material. Since most biomass fuels, however, are highlyreactive and contain little sulphur, they can be burnt efficiently in a BFB boiler, and the BFB technology is

typically more competitive in small scale biomass applications.

Grate firing may maintain its position with certain difficult biomass fuels.

The co-combustion applications described earlier also become more common, particularly in caseswhere waste such as biomass is to be disposed of, or biomass of little value is otherwise available. The ability tocompete of the various technologies (separate gasifier, integrated fluidised bed/grate firing, pulverisedcombustion) depends a great deal on the situation, form of biomass, further utilisation of ash, and properties of the existing coal fired boiler.

It seems that the combination of using small scale biomass, linked with the use of large scale coal isthe best way of using biomass in an efficient way. The best technology of linking coal and biomass still has to

be determined, and a lot of comparative engineering work still remains to be done.



02001Ren9788 April 199723

The future of the diesel engines connected with the gasifier and the IGCC technology depends on thetechnical development and the ability to compete achieved through progress and learning.

Small biomass gasifiers producing syngas for motors or gas turbines in unit sizes below 10 MWe mightreach their commercial potential within the next 10 years. Compared with the natural gas installations, the

costs for installations need to be reduced to approximately half of today’s level, or the units must be capable of running without manning. No break-through is anticipated which would make this possible. Compared with theconventional combustion techniques, the competition is only a little easier.

For larger gasification units, over 8 MWe, small demonstration units need to prove the bio-IGCCavailability and environmental performances before commercial units will be built. The development is mostlikely to follow a learning curve, where today’s sizes of 8 MWe will be 3-4 times as expensive as a natural gas - based unit, depending on the atmospheric or pressurised gasification technique. After the erection of some unitsalong the learning curve, unit sizes above 50 MWe may become commercially available. There are not,however, many sites for such large plants. Until this goal is reached, development is necessary within the areaof feeding and gas cleaning.

The future outlook for gasification is a higher efficiency in the production of electricity through the useof gas turbines compared with conventional combustion and the use of steam turbines. This again calls for anintensive development of low NOx combustion techniques using low calorific syngas to be used in small andmedium sized gas turbines.

The various EU projects for biomass gasification, and the use of syngas in gas turbines, seem to be lessenergetic. The reason could be that the gas turbine manufacturers do not see the need for developingcombustion chambers and burners for syngas, as there is nearly no market for this application. It is difficult toimagine who would provide the money for this development, considering competition on the electricity marketand the small market for such units.

The conclusion is that there is no quick break-through for gasification. A few demonstration projectsare coming up. Another 10 years will pass before the commercial use of biomass gasification and particularlythe short rotation forestry have been demonstrated.

The most important incentive for the use of biomass is the reduction of CO2 emissions. However, thisis not self-evident. The reduction of CO2 emissions is only obtained in case the use of a certain biomass-boundC is counteracted by the capture of the same quantity of C by growing plants. In order to make sure that Ccapture will take place, it is necessary to take this initiative of planting new biomass. This can take the form of giving way to new ”natural forests” or by growing short rotation coppice. The other way is severe attacks fromthe ecologists.



Publications Order Form

Name:...............................................................................................................................................

Position:............................................................................................................................................

Undertaking:.....................................................................................................................................

Address:............................................................................................................................................

Town: .......................................................Country:..........................................................................(with postal code)

Telephone:.......................................................Fax:..........................................................................(with regional code)

E-mail:…………………………………………………………………………………………………

EURELECTRIC member: p Yes p No (Tick the appropriate box)

Reference No. Title1

Quantity

To be returned to:

Concetta PALERMO – Union of the Electricity Industry - EURELECTRICDocumentation

66, Boulevard de l’Impératrice – BE-1000 Brussels

Tel.: + 32 2 515 10 00Fax: + 32 2 515 10 10

E:mail: [email protected]: http://www.eurelectric.org

1

Some documents are available in French (FR) and German (DE).Please indicate the language of your choice, when possible.



Documents

Energia Electrica a Partir de Biomasa