CO-COMBUSTION OF GASIFIED BIOMASS IN COAL- FIRED …CO-COMBUSTION OF GASIFIED BIOMASS IN COAL-FIRED POWER PLANTS -AN EFFECTIVELY WAY TO REDUCE CO 2 EMISSIONS . ... 9 RETROFIT OF FYNSVAERKET

VATTENFALL RESEARCH AND DEVELOPMENT AB Repor t Number

2008-08-07

Samuel Nilsson

Master Thesis Report

Umeå University

Sweden

CO-COMBUSTION OF GASIFIED BIOMASS IN COAL-FIRED POWER PLANTS

-AN EFFECTIVELY WAY TO REDUCE CO2 EMISSIONS

From Date Serial No.

Vattenfall Research and Development AB, Power plant and process technology (UVN)

2008-06-10 U 08:64

Author Access Project No.

Samuel Nilsson Full Access PR.81.06.09

Customer Reviewed by

Gerth Karlsson

Anders Nordin (Umeå University)

Issuing authorized by

Åse Myringer

Key Word No. of pages Appending pages

Biomass, gasification, indirect co-firing, coal, Fynsvaerket, CO2 reduction

101 18

Summary

Biomass is one of the most promising renewable energy sources to replace the fossil fuels, since it has the characteristic to be a feedstock both for production of chemicals and liquid/gaseous fuels as well as for green power production. The increased demand of upgraded and clean biomass has raised the costs of fuels significantly, which make utilization of waste wood and residues more interesting. One promising way to effectively utilize these fuels is by substitute some of the energy input from coal with gasified and cleaned biomass in large coal-fired power plants. This increases the effectiveness of biomass since these plants operates with higher efficiencies than stand-alone biomass-fired plants. The investigation showed that the actual gasification process of biomass is close to commercial, after a couple of demonstration plants have been in operation with purpose to direct combust the product gas in boilers without gas cleaning. However, much development with gas cleaning has been recently and two plants based on co-firing gasified and cleaned biomass/wastes are for the moment in the negotiation and permitting phase. The main factors for profitability for such a plant are:

• Subsidies for renewable electricity production. • High prices for CO2 emission quotas. • Relative low prices for the substitute fuel.

A case study has been done to investigate the feasibility to implement this concept at Fynsvaerket coal-fired CHP plant in Odense, Denmark. The concept includes a 120 MWfuel gasifier, with gas cooler and hot gas filter, connected to the coal boiler via large gas burners. The reduction in CO2 emissions is in order of 270 000 tons/year. Technically and logistically, this concept seems to be possible to implement at the plant area in a near future. However, a main risk with this concept may be that coal prices rises to levels that make the plant unprofitable for continuous operation. There is also a new 120 MWth, biomass fired plant under construction at the plant, which will act as main load to the district-heating network and take some of the load from the coal boiler. To retrofit a coal boiler with a gasifier unit requires long annual operation time for profitable, due to the high investment cost. The main technical barriers to overcome in co-firing gasified biomass are:

• The gasifier filter ash treatment. Tests have shown that the content of unburned carbon may exceed 26 %. To improve the plant efficiency and minimize environmental problems, the filter ash treatment has to be further investigated.

• Flue gas cooling and gas cleaning. Fouling and plugging in the cooling section, and tar condensing in the cleaning system have suffered many plants.

The economical calculations for the case study indicated a net present value (NPV) of 71 MEUR and an internal rate of return (IRR) of 22 % under an economical lifetime of 20 years, which must be considering being acceptable. The pay-off time is about 5 years.

Main process diagram of a gasification plant for co-combustion of biomass with coal.

Distribution list Company Department Name Number of

Table of Contents Page

1 INTRODUCTION 1

1.1 Introduction 1 1.2 Problem background 1 1.3 Objective 2 1.4 Scope 3 1.5 Energy policy within Europe 3

2 THEORY OF GASIFICATION 5

2.1 Combustion, gasification and pyrolysis 5 2.2 Advantages for biomass gasification 7

3 FUELS FROM BIOMASS 9

3.1 Biomass properties 9 3.1.1 The waste incineration directive 12

3.2 Fuel pre-treatment 13 3.2.1 Drying, chipping and grinding 13 3.2.2 Torrefaction 16 3.2.3 Pyrolysis and pre-gasification 16

4 GASIFICATION TECHNOLOGIES 17

4.1 Different gasification technologies 18 4.1.1 Fixed (moving) bed gasification 19 4.1.2 Fluidized bed gasification 20 4.1.3 Entrained flow gasification 21

4.2 Previous Vattenfall work on gasification technology 22

5 GAS CLEANING AND PROCESSING TECHNIQUES 25

5.1 Gas cleaning 25 5.2 Particles 27 5.3 Tars 27

5.3.1 Thermal tar cracking 29 5.3.2 Catalytic tar cracking 29

5.4 Alkali and chlorine 29 5.5 Treatment of by-products 30

6 GASIFICATION PLANTS OF INTEREST ON THE MARKET TODAY 31

6.1 Gasification with gas engine for heat and power production 33

6.1.1 Güssing power plant 33 6.1.2 Skive power plant 35 6.1.3 Kokemäki power plant 36

6.2 Gasification for co-firing in a boiler for heat and power production 38 6.2.1 Kymijärvi power plant 42 6.2.2 Electrabel power plant in Ruien 47 6.2.3 ESSENT power plant in Geertruidenberg 47

7 CONCEPTS OF INTEREST BASED ON GASIFICATION FOR POWER

PRODUCTION 49

7.1 Co-firing derived fuels without gas cleaning in a boiler 49 7.2 Co-firing complex fuels with gas cleaning in a boiler 50 7.3 Gasification of biomass for small scale CHP production with gas engines 51

8 FINAL GASIFICATION CONCEPT 53

9 RETROFIT OF FYNSVAERKET BLOCK 7 WITH A GASIFIER FOR CO-FIRING

BIOMASS 56

9.1 Description of the Fynsvaerket CHP plant 59

10 PROCESS STUDY 62

11 DESIGN STUDY 70

11.1 Introduction 70 11.2 Biomass storage, conveying, drying and preparation 71 11.3 Gasification system 72 11.4 Gas cooler system 73 11.5 Gas cleaning system 73 11.6 Fuel feeding system 75 11.7 Ash handling system 76

12 ECONOMY OF INDIRECT CO-FIRING SYSTEMS 78

12.1 Economics in general 79 12.2 Economical presumptions 79 12.3 Operational and maintenance costs 80 12.4 Capital cost 81 12.5 Profitability calculations 83

13 LOGISTICS AND PLANNING 88

14 EVALUATION AND CONCLUSIONS 89

14.1 General conclusions for indirect co-firing techniques 89

14.2 Conclusions of retrofitting Fynsvaerket with a gasifier 90 14.3 Further work 92

15 ACKNOWLEDGEMENTS 93

16 ABBREVIATIONS 94

17 REFERENCES 96

Appendices Number of Pages

APPENDIX pp

1 PLANT VISIT AT THE KYMIJÄRVI POWER PLANT 7

2 SUBSIDIES FOR ELECTRICITY GENERATING PLANTS IN DENMARK 3

3 PICTURES AND LAYOUT OF FYNSVAERKET 2

4 PROCESS CONDITIONS FOR BLOCK 7 5

5 PROFITABILITY CALCULATIONS 1

Vattenfall Research and Development AB U 08:xx

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1 Introduction

1.1 Introduction

Worldwide energy supply for power production is currently mainly based on fossil fuels. The use of these fuels is responsible for a large part of global carbon dioxide emissions to the Earth’s atmosphere. It is widely understood that these emissions increases the greenhouse effect, which will result in an additional warming of the atmosphere. Biomass is one of the most promising renewable energy sources considered to replace the use of fossil fuels and resulting in a reduction of CO2 emissions to the atmosphere because of its CO2 neutrality. Due to plant intake of CO2

from the atmosphere, bioenergy can be produced and consumed on a practically CO2 neutral basis (Kavalov and Peteves, 2004, Demirbas, 2002), see Figure 1. The European power company Vattenfall wants to be a part of the framework in the convertation to renewable energy sources, and is therefore interested in this investigation of effective power production from biomass.

Figure 1 Mechanism of the closed CO2 cycle system1 (Kavalov and Peteves, 2004).

1.2 Problem background

Biomass is a promising renewable energy source to replace the fossil fuels, since it has the characteristic to be a feedstock both for production of chemicals and liquid/gaseous fuels as well as for green power production. The use of biomass in industrial application and for heat and power production grows for every year. At the same time research and development for biomass to

1 a) CO2 is captured by the growing crops and forests. b) Oxygen (O2) is released and carbon (C) is stored in the vegetation. c) Biomass (carbon) is harvested and transported to the power plant. d) The plant combust the carbon by oxygen and CO2 is formatted and released to the atmosphere and later captured by the vegetation (Kavalov and Peteves, 2004).


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liquid/gaseous fuels are increasing and seems by many scientists to be part of the solution in the conversion from fossil to renewable fuels in the transportation sector. As the market prices for raw clean biomass as feedstock is increasing by the higher demands, it will be of interest to use cheaper fuels like waste fuels, residues, MSW and bio-fuels difficult to burn in conventional boile rs. The problem with these fuels are often the higher contents of undesired components like alkali metals, heavy metals, chlorine, low temperature and ash-melting components. When using these fuels in traditional CHP plants, fouling, slagging and corrosion problems occur mostly in the convection zones. Severe problem with bed agglomeration is common in application using fluidized bed technology. By lowering the steam and furnace temperature the problem reduces but affects the electricity generation negative ly. One method to undergo this problem is to gasify the feedstock in a gasifier and clean the raw gas from these problematic components and then either burn the gas in a boiler with higher steam data, for gas engine application with electricity production or burnt in a integrated gasification combined cycle (IGCC). An alternative way is to clean the gas for further production of bio-fuels like methanol, Fisher-Tropsch diesel (FTD), di-methyl ether (DME) or use it for power production in fuel cells.

1.3 Objective

The purpose of this project is to investigate the possibility to establish cost efficient, highly available, biomass gasification technology for increased power production. With focus on reduction of carbon dioxide to the atmosphere and increase the use of renewable fuels for power production, Vattenfall has started a large investment in research and development of alternative energy sources and carbon dioxide capture and storage technology (CCS) from fossil fuel fired plants to reduce the amount of CO2 to the atmosphere. One of these project goals will be focused on biomass combustion and gasification technology. This study will investigate the possibility to establish biomass gasification technology for heat and power production. A literature study of the state-of-the-art biomass gasification technology will be done. Plants working on gasification technology on the market today will be further investigated. At least three gasification concepts will be stated and further analysed with respect to technical and economical advantages and then a main analysis will be done for one of these concepts. This concept will be a completely techno-economic analysis of the feasibility to implement a gasification heat and power plant at one of Vattenfall AB’s existing sites in Europe. The aim of the project will be focused on following:

• The total investment cost for a gasification facility including fuel treatment, gasifier, gas cleanup, following application and other essential facility equipments.


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• A technical process study for a gasification concept at one of Vattenfalls sites in Europe.

• Different kind of technology for biomass gasification (type of gasifier, fuel pre-treatment, hot/cold gas cleanup, gasification medium (O2, air, steam), pressurised/atmospheric gasif ication.

• Status for new technology in biomass gasification and the driving forces for future development in gasification technology will be investigated.

• Investigate possible providers of the technology.

1.4 Scope

The study is limited to consist of gasification of biomass for increased power production and no conversion of the synthetic gas to liquid/gaseous fuels or hydrogen cells application will be investigated. IGCC applications may only be described shortly and is not a concept that will be deeply investigated. No investigation in black liquor gasification will be analysed either. Vattenfall AB’s previously work on gasification concept mainly consists of the project VEGA (Vedförgasning), in the beginning of the 90’s. VEGA included an IGCC concept for pressurized gasification of biomass. The plant was based on an air-blown FB-gasifier with hot gas cleanup and was projected for 140 MW fuel to be located in Eskilstuna, Sweden (Liinanki and Karlsson 1994). However, the concept never became reality because of the negative economical feasibility. In the late 80’s Vattenfall was engaged in a project to develop biomass gasification (CFBG) and gas cleaning technology for the purpose of power and district heat cogeneration by means of a large, turbo charged diesel engine.

1.5 Energy policy within Europe

Energy policy for Europe

A summary of the European Union’s Energy policy and their goals (Hansson et al., 2007).

• 30 % reduction of GHG to the atmosphere from developing countries in 2020. Minimum reduction for the EU countries has been set to 20 % under the same period.

• Minimize the energy consumption by 20 % before 2020. • Increase the use of renewable energy sources by 20 % before 2020. • Increase the use of biomass as fuel in the transportation sector by 10 % before

2020. These specific goals stated for 2020 replaces commitments from Rio de Janeiro -92, Kyoto -97 and the goals from EU: s “Green paper”, which was planned for 2010.


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The new goals are more specific and focused to increase the ambition to solve the environmental problems related to CO2 emissions. The renewable energy sources stated for energy production are as followed:

• Wind power • Hydropower • Solar cell • Biomass • Thermal solar energy • Waste recycling

Political directions and rules, set up by each country, will be tools to achieve the goals. Important control measurements will be taxes, restrictions and support for research and development. The introduced system for trade with emissions quotas – EU ETS (European Emissions Trading Scheme) – is supposed to be an effectively driving force to reach above-mentioned goals. Trading with emissions quotas EU: s directive of trading with emissions quotas was introduced the first of January 2005. The purpose was to let the countries and companies decide if they want to reduce their emissions by introducing new technology or if they want to buy quotas to reduce the emissions somewhere else. The system is based on a maximum annual emissions limit under a trading period. The maximum is set on a plant perspective, which means that the plant owner is given a number of quotas for selling and buying. One quota gives the plant right to release one tonne of CO2. The price for the emissions quotas has fluctuated quite much during the test period between 2005 and 2007. Prices between 1 to 30 EUR/tonne CO2 have been achieved, which primary may depend on a too large amount of quotas available on the market. The expected prices for the quotas next coming years are estimated to be around 20-25 EUR/quota (Hansson et al., 2007). The introduced system with trading of emissions quotas (EU ETS) will probably be one of the most powerful driving forces in the development around the energy sector in the future (Hansson et al., 2007). The trading with emissions quotas favours more effective energy production and the use of renewable energy sources.


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2 Theory of gasification

2.1 Combustion, gasification and pyrolysis

Biomass mainly consists of the elements carbon, oxygen, hydrogen and nitrogen. By adding heat and oxygen, several products can be formed depending on how much oxygen being added. For complete combustion, the added oxygen (and oxygen in the fuel) needs to be sufficient to combust all carbon and hydrogen in the fuel to CO2 and H2O, i.e. an oxygen ratio of 1.0. This oxygen ratio is generally called lambda-value (?) and a lambda-value of 1.0 is called combustion with stoichiometric conditions. In combustion processes you normally have a ?-value of about 1 to 1.5 to guarantee complete combustion (Olofsson, 2005). When lambda-value is between 0 and 0.2 it is said to be a pyrolysis-process. Above this state and up to lambda-value slightly below 1.0 the reaction is called gasification. However, gasification-processes normally do not exceed ? = 0.3 to 0.4. At these lambda-values the concentration of the main combustible gaseous products CO and H2

are the highest and the solid material from the feedstock has been volatilized. The main chemical reactions taking place in the gasifier are (Krzysztof et al., 2005):

COCOC 22 =+ molkJH /6,172=∆ (1)

22 HCOOHC +=+ molkJH /4,131=∆ (2)

422 CHHC =+ molkJH /9,74−=∆ (3)

22 COOC =+ molkJH /5,393−=∆ (4) The isotherms at 832°C and 600°C in Figure 2 indicate the solid carbon-boundary lines in a ternary C-H-O diagram. Above the carbon-boundary line, solid carbon exists in heterogeneous equilibrium with gaseous components, and below the line only gaseous components are present in homogeneous phase equilibrium. To reach perfect gasification (maximize heating value of the gas), oxygen should be added until the solid carbon-boundary is reached. As an example: for coal, oxygen should be added (arrow in Figure 2) until point A is reached and complete gasification is achieved. If more oxygen is added, the produced gas loses its heating value, until the line from CO2 and H2O is crossed and complete combustion has taken place (Krzysztof et al., 2005).


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Figure 2 Location of bio-fuels in ternary C-H-O diagram (Krzysztof et al., 2005).

To increase the concentration of carbon monoxide and hydrogen in the product gas, oxygen or superheated steam can be added instead of air as gasification medium. This will eliminate the contents of inert nitrogen in the gas and also lead to a higher heating value of the product gas. However, the drawback of the oxygen-blown gasification is that it is much more expensive than the air-blown process, due to the high cost of oxygen production. Oxygen-blown gasification produces a gas with high heating value and is therefore of interest for applications with higher added value such as FTD or DME production, whereas it is not directly relevant for power and heat production at present (Maciejewska et al., 2006). Table 1 shows components and properties of product gases for some different technologies.


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Table 1 Main components and properties of product gas, obtained from different

biomass gasification concepts (Kavalov and Peteves, 2005).

A-CFB-air 2 A-CFB-O23 P(N2)-CFB-

O24

P(CO2)-CFB-O2

5

A-indirect -H2O6

P-EFG-O27

CO, vol. % dry

19,3 26,9 16,1 16,1 42,5 46,1

H2, vol. % dry

15,6 33,1 18,3 18,3 23,1 26,6

CO2, vol. % dry

15,0 29,9 35,4 46,9 12,3 26,9

CH4, vol. % dry

4,2 7,0 13,5 13,5 16,6 0,00

N2/Ar, vol. % dry

44,5 0,7 12,3 0,8 0,0 0,4

C2, vol. % dry

1,4 2,4 4,4 4,4 5,5 0,0

LHV [MJ/m3]

5,8 8,9 8,4 8,1 13,6 7,4

H2/CO ratio 0,81 1,23 1,14 1,14 0,54 0,58

2.2 Advantages for biomass gasification

Biomass is a renewable fuel that can be used for electricity production with minimum carbon dioxide emissions (Kavalov and Peteves, 2004). The traditional way to go is direct-combustion in conventional boilers with production of superheated steam and steam turbine for electricity production (Rankine-cycle). However, applying biomass combustion is related to problems with corrosion and fouling in the boiler, mostly caused by alkali and chlorine content in the fuel (FFP, 2007). One way to undergo this problem is by lowering the steam temperature/pressure leading to fewer problems but effect the power production negatively. Small-scale biomass-CHP also has very low electrical efficiency due to the avoidance of high investments in complex and expensive material for high steam temperatures. For cost-effective power production from biomass and for efficient use of the renewable fuels resources, more effective power production must be reality in the future. If the biomass is gasified, the produced gas can serve as fuels for gas turbine combined cycle, gas engine or be fired in a boiler with more advanced steam data. However, these methods are unproven for large-scale

2 A-CFB-air = Atmospheric air-blown CFB gasifier. 3 A-CFB-O2 = Atmospheric oxygen-blown CFB gasifier. 4 P(N2)-CFB-O2 = Pressurised (with nitrogen) oxygen-blown CFB gasifier. 5 P(CO2)-CFB-O2 = Pressurised (with carbon dioxide) oxygen-blown CFB gasifier. 6 A-indirect-H2O = Atmospheric steam blown indirect gasifier. 7 P-EFG-O2 = Pressurised oxygen-blown direct entrained flow gasifier.


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production and therefore related to high investment costs due to its relative new technology. With increasing prices of electricity, new political directives (ex. EU CO2 trading system, Swedish green certificate system, subvention for renewable power technology) and consumers willingness to pay premium prices for green power, these technologies can be of greatest interest in a near future. Some of the advantages of biomass gasif ication compared to direct combustion are:

• A renewable feedstock is used as fuel for green energy production, which has a positive impact on the CO2 emission to the atmosphere.

• Higher electrical efficiency due to more advanced steam data when firing/co-firing in a boiler.

• Separation of aggressive components before combustion (alkali, heavy metals, chlorine, ash etc.).

• More complex fuels can be used in indirect co-firing than direct co-firing. • Waste can be used as fuel without extra flue-gas cleaning equipment if the gas

has been cleaned before combustion. • Re-burning (NOx reduction) effect when co-firing in an existing plant. • Emissions of SO2 may be reduced when co-firing with coal. The sulphur

content in the coal may also have a negative impact on formation of alkali-chlorides from the biomass (FFP, 2007).

• Higher electrical efficiency when using integrated gas turbine combined cycle technology.

• Gas engines have higher electrical efficiency than traditional CHP plants working with steam turbine in the wide of 10-40 MWth.

• Cheaper and easier gas cleaning since the gas volume to be cleaned is three times less and so the concentration of impurities are higher.

• Less risk of slag formation in the boiler when firing in a boiler due to removal of the melting minerals in the ash.

• No dioxin is formed since the atmosphere in a gasifier is reduced (Veijonen et al., 2003).

• Heavy metals and up to 90-99 % of the chlorine can be removed before gas combustion with extensive gas cleanup (Veijonen et al., 2003).

• The biomass ash is not mixed with coal ash when indirect co-firing is applied, which makes ash treatment unaffected.


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3 Fuels from biomass Biomass is a renewable energy source with minimal CO2 emissions due to its CO2

neutrality. However, the term neutrality is not completely true, because of the small amount of fossil fuel that is consumed in the biomass cycle (ex. cultivation, transportation etc.). The amount of fossil fuels consumed is modest, typically between 2 % and 4 % of the total energy supply from biomass (Kavalov and Peteves, 2004). In Europe, it is typical that about 30-100 MW of bio-fuels and suitable waste-derived materials are available within 50 km from a given power plant (Wilén et al., 2004), which is a sufficient amount to gasify and utilize in medium or large scaled gasifiers.

3.1 Biomass properties

Biomass, for energy production, can be divided into woody and herbaceous materials. Woody biomass includes stem wood from ordinary forestry, short-rotational forestry and various residues and wood wastes (Kavalov and Peteves, 2005). Many different types of biomass can be utilized in gasification systems. Gasification experience includes wood, residues from forestry and related industry, agricultural residues, as well as various upgraded biomass in forms of pellets. Upgraded biomass makes it possible to import biomass from regions where biomass is produced in large quantities such as North America, Scandinavia, Russia and other Northern European countries. These upgraded fuels are often related with high prices due to its upgraded form and transportation way. The most important properties of biomass to be used for gasification are the ash content and its composition, causing problems with bed agglomeration and slagging, not the content of oxygen, hydrogen, carbon and nitrogen (Jonsson, 2006). Biomass is also associated with terms of low heating value, low bulk density, high moisture and ash content and high concentration of alkalis and chlorides. This makes some of the types of biomass more or less not suitable for direct combustion because of higher risk of fouling and corrosion. These problems can be minimized if the biomass is gasified and cleaned from fuel-based contaminants before being fired. A variety in feedstock is preferred, since prices of stem woody and other clean bio-fuels are increasing yearly. Technically and theoretically, almost all kind of biomass feedstock is possible to gasify but most of them are associated with either operational problems or/and environmental hazardous emissions. Different kind of fuels for interest in this project are listed below:

• Refuse derived fuel (RDF) (classified as waste fuel). • Herbaceous materials (straw, grass, energy crops, wheat, barley). • PWP fuels (paper, wood and plastics) (classified as waste fuel).


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• Waste wood (construction and demolition waste) (classified as waste fuel if it contains heavy metals and/or halogenated organic pollutants).

• Energy forest. These fuels are all related to some operational problems in conventional CHP plants and are therefore relative cheap fuels. Some fractions of waste, the receiver even gets paid for as for example some kind of RDF fuels. The choice of fuel to use depends on used application, the price and the availability of the fuel close to the plant. Characteristics for some of the fuels are listed in Table 2 and Figure 3.

Table 2 Characteristics of different fuels (Strömberg, 2005).

Type of fuel Fuel characteristics Problem associations

PWP (paper-wood-plastics)

Inhomogeneous fuel.

High heating value.

High moisture and ash content.

Can contain high amounts of chlorine, Zn and Pb

The ash may be polluted with high amounts of heavy metals, which makes it necessary to deposited as landfills or cleaned for reuse as fertilizer.

The in homogeneity can be improved by having a good fuel mixture.

Risk of deposits and corrosion problems.

PWP is covered by the WID.

Emissions: NOx, SO2, CO, hydrocarbons, dust, HCl, heavy metals.

Waste wood Elevated contents of ash and impurities.

Cheaper than other wood fuels.

The ash may be polluted with high amounts of heavy metals, which makes it necessary to deposited as landfills or cleaned for reuse as fertilizer.

Waste wood is covered by the WID if it includes heavy metals and /or halogenated organic pollutants.

Highest proportion of impurities in the smallest particle fractions.

Risk of corrosion and deposits.

Emissions: NOx, SO2, HCl, CO, hydrocarbons, dioxins/furanes, heavy metals and dust.

Straw Low bulk density => increased costs for transportation and storage.

Difficult to feed in the boiler.

High amounts of ash, alkali and chlorine.

Low ash melting temperature.

Price as waste wood (in Sweden).

The ash can be reused as fertilizer.

Risks of spontaneous ignition during storage of moist straw.

Risk of corrosion and deposits.

Risk of bed agglomeration.

Emissions: NOx, CO, hydrocarbons, dust, HCl.

Energy forest Elevated contents of heavy metals.

Uniform particle size with low proportion of fines.

The ash may be polluted with high

May give intensive combustion.

A high proportion of bark affects the combustion properties.

Emissions: NOx, CO, hydrocarbons,


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amounts of heavy metals, which makes it necessary to deposited as landfills or cleaned for reuse as fertilizer.

dust, heavy metals (Cd).

Figure 3 Influence of fuel characterization to boiler design (Veijonen et al., 2003).

Prices of different fuels in Sweden are illustrated in Figure 4 for the last 5-9 years.

0,00

5,00

10,00

15,00

20,00

25,00

1997 1999 2001 2003 2005 2007

Year

Upgradedwoody biomass(a,b)Stem wood fromforestry (a,b)

Woody residues(a,b)

Waste wood(a,b)

Milled peat (b)

Figure 4 Prices of biomass in Sweden. Taxes are not included8.

8 Reference: a: (Energimyndigheten, 2008), b: (Strömberg, 2005)


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Prices of different fuels in Sweden, Germany, Poland and Denmark in June 2006 are shown in Figure 5.

0,00

10,00

20,00

30,00

40,00

50,00

Sweden (EURO/MWh) 15,37 8,50 16,09 22,54

Germany (EURO/MWh) 10,04 5,40 1,87 41,80 5,08

Poland (EURO/MWh) 7,49 5,08 2,70 18,18 6,41

Denmark (EURO/MWh) 14,40 11,95 14,04 7,13

Forest residue

Ind. by product

Wood waste

Ref. wood Coal

Figure 5 Prices for different fuels in Europe in June 20069. Taxes are not included (prices

evaluated from Alakangas et al., 2007).

3.1.1 The waste incineration directive

The waste incineration directive (WID 2000/76/EC) is a EU directive for heat and power plants that uses waste classified fuels for energy production. The aim of the Directive is to prevent or limit as far as possible, negative effects on the environment and in particular pollution by emissions into air, soil, surface and groundwater, and the resulting risks to human health. The Directive aims to achieve this high level of environmental and human health by requiring string operational conditions, high technical requirements and emissions limits for incinerating and co-incinerating waste plants within the European Union (DEFRA, 2006). Technical requirement of the WID

• Operational conditions. At least 850°C after the last injection of combustion-

air for two seconds. At combustion of hazardous waste (that include more than 1 % of halogenated organic substances, expressed as chlorine), a limit of minimum 1100°C in two seconds must be achieved.

• Emission limit values for a range of substances to water and air. • Equipment for measuring the emissions (dioxins, PAHs etc.). • At least one automatic auxiliary is required in order to maintain the

temperature limits. This unit will be automatically and start as soon the

9 Prices in Poland are from June 2005. Prices for coal in Denmark is from June 2005. Prices for waste wood in Sweden has been recalculated to more reliable values.


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temperature drops to the required temperature. Auxiliary burners are not required for co-incineration plants and gas engines/turbines. (Padban et al., 2002 & DEFRA, 2006)

• Continuous measurements of NOx, CO, dust, organic carbon, HCl, HF, SO2. Emission limit values for incinerator plants are listed in Table 3:

Table 3 Emissions limits (daily average values) to air for incineration plants at 1 bar, 273

K and 11 % oxygen in flue gases (DEFRA, 2006).

3.2 Fuel pre-treatment

Biomass for gasification processing does almost always need some kind of pre-treatment as drying or chopping before entering the gasifier. Raw biomass has a relative high water content and for optimal gasification conditions drying is required. Pre-treatment, as minimizing the size of the feedstock, is preferred and depends on following process application. All these treatment requires extra energy supply and additional capital costs but are followed by fewer problems and less operational costs and can be re-paid in size reduction of the gasifier and the gas processing equipments. Some gasifier requires more pre-treatment than other, like entrained flow gasifiers, while there is gasifiers today working with un-dried and only partial chopped biomass with water contents above 50 % (see Kymijärvi power plant, chapter 6.2.1).

3.2.1 Drying, chipping and grinding

The moisture content of raw biomass is usually highly resulting in a relative low calorific value of the fuel. Fresh wood typically contains 25-55 % water by weight. For gasification application, moisture content of 15-20 % is most suitable (Jonsson, 2006). Moisture content of biomass affects its combustion properties by reducing the maximum combustion temperature and increases the necessary residence time of feedstock in a combustion chamber. This could result in an incomplete combustion

Total dust 10 mg/m3

Gaseous and vaporous organic substances, expressed as total organic carbon.

10 mg/m3

Hydrogen chloride (HCl) 10 mg/m3

Hydrogen fluoride (HF) 1 mg/m 3

Sulphur dioxide (SO2) 50 mg/m3

Nitrogen monoxide (NO) and nitrogen dioxide (NO2), expressed as nitrogen dioxide for existing incineration plants with a nominal capacity of exceeding 6 tons per hour or new incineration plants.

200 mg/m 3

Nitrogen monoxide (NO) and nitrogen dioxide (NO2), expressed as nitrogen dioxide for existing incineration plants with a nominal capacity of 6 tons per hour or less.

400 mg/m 3


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and increased emissions related to it (Maciejewska et al., 2006). The main advantages for pre-drying the biomass is lowering the need of gasification medium, reduce the size of the gasifier and the volumetric flow rate of the fuel gas, and results in a higher heating value of the produced gas (Jonsson, 2006). It also reduces the dry matter losses during storage but increases risk of fires. The effect of moisture content and calorific value of biomass can be seen in Figure 6.

Figure 6 Effect of calorific value and moisture content of the biomass on temperature

and gas calorific value (Jouret et al., 2005).

Natural drying of biomass can reduce the moisture content to 30 % but lowering down to 15-30 % requires forced drying. Forced drying can be done with hot air, flue gases or with hot steam. This can be done direct or indirect via heat exchangers. Forced drying at the gasification plant requires energy and increases the capital and operational cost for the plant. The heat needed to evaporate 1 kg of water from a typical biomass fuel can exceed 2,6 MJ10, where typical LHV of dry biomass is 18-21 MJ/kg (Maciejewska et al., 2006). During the drying process, VOC: s can be released, which makes the need of some kind of flue gas cleaning system necessary. Forced drying of biomass will increase the total cost of fuel treatment significantly, but on the other hand increase the combustion efficiency and reduce the flue gas volume flow and the need of complex combustion technology and process controlling. One of the major problems related to drying biomass with flue gases or air are the emissions of VOCs to the atmosphere. These types of dryers require expensive cleaning equipments to separate the VOCs. Värmeforsk has investigated different

10 The evaporation enthalpy for water at 25°C and 1 bar is hevap. = 2,26 MJ/kg.


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techniques with combustion, thermal and catalytically, to reduce these emissions. By the abstract in the report, following could be stated:

• The gas cleaning investment cost for a plant dimensioned for 60 000 Nm3/h11 is calculated to 0,43 – 0,7 MEUR12 for thermal combustion and 0,64 – 1,06 MEUR12 for catalytically combustion, includes regenerative heat recovery. The purification cost for a typical case (400 mg/Nm3 VOC) is estimated to about 2,34 EUR12 per kg removed organic matter in both cases (Nielsen and Ehrstedt, 2000).

An alternative way to dry the feedstock is to use steam indirectly via heat exchangers. This eliminates the emissions of VOCs to the atmosphere and the formatted condensate is the only that needs to be cleaned. Removal of environmental hazardous solutions is much easier to separate from condensate than from flue gases or air. Before entering the gasifier, chipping and milling of the biomass might be optimal and necessary. For FB gasifiers, the maximum size of feedstock is about 50-150 mm and for entrained flow gasifier the feedstock must been grinded or torrefied or reformed to a liquid or a gas. The energy need for chipping is about 1-3 % of the energy content of the biomass fuel (Maciejewska et al., 2006 + Olofsson et al., 2005), while for milling the costs may varying between 10-20 % (Olofsson et al., 2005) depending on particle size (see Figure 7).

Figure 7 The power consumption for milling of biomass in relation of average particle

size for wood and torrefied wood (van der Drift et al., 2004).

11 60000 m3n/h correspondences to a plant with size 35 MWth (Framtidsbränslen, 2005). 12 The costs have been converted from SEK to EURO with a ratio of 0,106.


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3.2.2 Torrefaction

Torrefaction is a thermal treatment of the biomass in the absence of oxygen for 15-60 min at 200-300 °C and atmospheric pressure (Kavalov and Peters, 2005). The moisture in the biomass is used and superheated to dry the biomass in an oxygen free atmosphere. With this treatment, the biomass is converted into a coke-like product, which is easier to grind than dried chips of biomass. The drying time is said to been reduced by 80 % and the energy supplied reduced with 50 % compared with conventional drying with hot air (FramTidsbränslen, 2005). The energy consumed on grinding torrefied biomass is 10-20 % compared to fresh wood grinding (Nordin, 2008). Advantages of high energy density and hydrophobic character makes it easy to transport and store without risks of fires. This concept can be of great interest also when biomass is direct co-fired in PC burners. When applying torrefaction, the biomass losses 10 % of its energy contents (van der Drift et al., 2004). An economical study was done comparing conventional drying to torrefaction of biomass in a pilot study for BTL production in Sundsvall, Sweden. This study showed that drying via torrefaction has an economical advantage (5-12 % cheaper) than conventional drying since the energy need for drying via torrefaction is reported to be 50 % less than for conventional drying. If the next-coming process needs milling, the economical benefit will be even higher, because of the lower electric ity consumption for milling processes. No cost for investment was included in the study (FramTidsbränslen, 2005).

3.2.3 Pyrolysis and pre-gasification

Pyrolysis is a technology, which thermally converts solid biomass to liquid form by fast heating of the fuel in absence or very small amount of oxygen. Pyrolysis temperature varies usually from 400 to 600°C and the liquid content is yield by fast pyrolysis technology. The heat needed for the pyrolysis is by combustion of the non-condensable combustible gases and residual char. The conversion from solid biomass to liquid product varies depending on biomass, pyrolysis process, etc. and is typically 40-65 % on energy basis (Nieminen and Karki, 2007). This is a quite expensive pre-treatment, but can be suitable for pressurized gasification systems and for entrained flow gasifiers. Some herbaceous fuels could also be effectively pyrolysed, since they are associated with low bulk density and are difficult to shred.


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4 Gasification technologies There is a wide range of application for biomass gasification technology, but plants on the market today are mostly in demonstration or pilot scale and only a few are in commercial operation. The alternative ways to go when gasifying feedstocks are illustrated below in Figure 8.

Figure 8 Different applications of gasification systems for power production (Rensfelt,

2005).

After a market penetration it seems to be extra focus on new developing biomass gasification technology concentrated to three major applications. These are:

• Electricity production with gas engine. • Production of BTL fuels and methane for the transportation sector. • Production of LHV gas for combustion or co-combustion in steam boilers.

Bio - IGCC technology still has to be further developed and economical feasible before applied in larger scale for power production. Problems with low availability, high investment cost and extensive gas cleaning, necessary for the gas turbine, requires more R&D technology before becoming real interesting. However, developing and establishing in coal – IGCC seems to be more and more attractive, where China is a major actor on the market. These applications are mostly in large scale and uses EF-gasifiers. Some of these plants uses a mix of biomass and coal as feedstock and development around CCS technology for IGCC applications seems to result in a demonstration plant in a near future. Maniatis stated some of the most interesting concepts integrated with biomass gasification with following figures (Figure 9 and Figure 10).


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Figure 9 Status of applications for market potential and technology reliability (Maniatis,

2001)13.

4.1 Different gasification technologies

Maniatis has also stated technology development and market attractiveness for electrical power production from gasification application in Figure 10.

Figure 10 Technology development and market attractiveness for electrical power

production from gasification applications (Maniatis, 2001)14.

After a market investigation, focus on biomass gasification for heat and power generation seems to depend on which kind of application being used:

• For IGCC applications, most research and development seems to be on EF and indirect FB gasifiers, both for coal and biomass gasification.

• Small-scale CHP plants with gas engine are most developed with moving bed and direct FB gasifier.

• FB gasifiers almost dominate the market within co-firing/firing technology in large boiler applications.

Three gasifier types have been considered for gasification: fixed (moving) bed gasifiers, entrained flow gasifiers and fluidized bed gasifiers. These types of gasifiers are the most widely used today and new unproven gasifier technology has not been

13 There have been an increasing market potential and new developing for fuel production via biomass gasification technology since 2001. 14 In the original figure the markets low and high were located at wrong places. Correlation has been made in figure 10.


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included in this study. The gasifiers, named above, can be varying a lot considering pressure, gasification medium, flow direction, indirect gasification and circulating- and bubbling fluidizing for FB-gasifiers.

4.1.1 Fixed (moving) bed gasification

Technology description Fixed bed gasifiers have been in use for the longest time and therefore use the oldest technology. It is applied in relatively small scale, normally up to 10-15 MWth, (Olofsson et al., 2005) for production of fuel gases for direct combustion or in gas engine in order to produce electricity. The up scaling is limited due to the fixed bed technology since it is hard to keep a large fuel bed with uniform temperature distribution. It is more difficult to achieve efficient heat transfer in a downdraft gasifier than in an updraft gasifier, thus updraft gasifier can be larger. They are classified as different kind of fixed bed gasifier, depending on direction of mass flows of air and fuel. In downdraft gasifier, Figure 11 (right), the fuel is fed at the top and the gasification medium is introduced into a downward flowing packed bed. The product gas is drawn of near the bottom. In an updraft gasifier, Figure 11 (right) the fuel is fed at the top of the gasifier and the gasification medium is introduced at the bottom. The product gas leaves at the top of the gasifier. Other types of fixed bed also exist, but they are more or less built on same technology.

Figure 11 Updraft and downdraft gasifier (Olofsson et al., 2005)

Advantages/disadvantages • A lot of operation experience is available (several plants exist with operation

hours between 5000-20 000). • A lot of fixed bed gasifiers with several applications are in use today.


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• Restricted to small and medium sized plants (updraft < 10-15 MWfuel), (downdraft < 5-10 MWth).

• Generally low availability (<60%) (Hofbauer, 2007). • High specific investment costs (Hofbauer, 2007). • High electricity production costs (Hofbauer, 2007). • High tar content (updraft gasifier). • A high exergy loss due to large portion of the fuel-energy is converted into

heat (downdraft gasifier) (Olofsson et al., 2005). • 4-7 % of the carbon is not converted (downdraft).

4.1.2 Fluidized bed gasification

Technology description A fluidized bed is a bed of solid particles (sand, limestone, ash etc.) fluidized by forcing air through the bed. Fluidized bed gasifiers can be divided into circulating fluidized bed, CFB (Figure 12, right), and bubbling fluidized bed, BFB (Figure 12, left), gasifiers depending on fluidizing air velocity. When the air velocity is increased above the minimum fluidization velocity, air flows through the bed as bubbles (BFB). When the air velocity is further increased the particles are carried higher up in the reactor and a large fraction of the particles rise up from the bed and are re-circulated to the bed with help of a cyclone and a returning leg (CFB). Fluidization air velocity for a BFB is in the range of 1-3,5 m/s, whereas for a CFB around 3-6 m/s (Veijonen et al., 2003). When using biomass as fuel for combustion, fluidizing bed technology is the most common used technology. FB combustors have several advantages over other combustors, like roasting beds, fire grates, since they offer almost optimal mixing of fuel and gasification medium, high thermal transmittance and long residence time. The gasification temperature is also relative low (800-1000°C) resulting in lower formations of thermal NOx. BFB gasification technology seems to be more economically suitable for medium size applications (15-80 MW), while the CFB technology is most economic in larger scale (40-100 MW) (Nieminen and Karki, 2007).


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Figure 12 BFB and CFB gasifier (Olofsson et al., 2005).

Advantages/disadvantages • Most mature technology (Several plants with 20 000-60 000 operation hours) • High commercial availability (most industrial applications, co-firing- and

combustion CHP plants). • Large range of capacities (5-150 MWfuel). • High fuel flexibility • Availabilities in the range of >85%. • Relatively high investment costs (Hofbauer, 2007). • Long residence time and good mixing of the fuel. • Risk of bed agglomeration. • Advanced technology.

4.1.3 Entrained flow gasification

Technology description The entrained flow gasifiers, see Figure 13, generally use fuels in the form of gas, slurry or powder to produce product gas. The fuel is mixed with oxygen/steam and gasified in a turbulent powderized flame at high temperature (above 1200°C) in a very short time (a few seconds) (Olofsson et al., 2005). With these high temperatures an almost tar-free product gas is produced and the ash components forms a molten slag. The hot gas flows downwards and cools down before it exits the vessel for further treatment.


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Figure 13 Entrained flow gasifier (Olofsson et al., 2005)15.

Advantages/disadvantages • Has been in use for a lot of experiences in coal gasification. • No need of a tar cracker unit. • Mainly for large size applications (>100 MWfuel) (Hofbauer, 2007). • Need oxygen as gasification medium (cost of oxygen: 0,6-0,8 SEK/kg)

(FramTidsbränslen, 2005). • Needs extra fuel pre-treatment as grinding, pyrolys or torrefaction, which may

increase the operational costs. • High amounts of sensible heat are produced during the gasification, requiring

integration with steam production for high efficiency.

4.2 Previous Vattenfall work on gasification technology

The Vattenfall work on biomass gasification has mainly been focused on air-blown, pressurized fluidized bed gasification with hot/dry gas cleaning for power generation in a gas turbine combined cycle. The goal of the VEGA project (1991-1994) was to demonstrate pressurized fluidized bed biomass gasification in a full-scale IGCC (100- 150 MWfuel). Some of the results from the project are followed:

• The gasification tests were done at VTT, Finland, in a 400-kWfuel, laboratory scale unit and in a 15 MWfuel pilot plant at Enviropower, Finland (Gaspi). The total operating hours at VTT was about 350 hours and at Gaspi about 600 hours. The gasification test program included an extensive sampling and analyses program for heavy metals and organic compounds in ash and product gas (Liinanki and Karlsson, 1994).

15 The picture shows a Texaco gasifier with a radiant syngas cooler where high pressure steam is produced.


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• Three types of dryers for the biomass was tested and the pressurized steam dryer seemed to be best suited for the considered feedstock (residues from the forest industry) (Liinanki and Karlsson, 1994).

• The ceramic high temperature filter has worked well for dust- and alkaline cleaning of the product gas with a dust content of less than 5 mg/Nm3 and alkaline content of less than 0,05 ppmw after the filter (Liinanki and Karlsson, 1994).

• 60-80 % of the nitrogen bound in the fuel is converted to ammonia at

gasification. 25-50 % of the produced ammonia is converted to nitrogen oxides at combustion in the gas turbine. This was less than expected but there is still a need of further NOx reduction (SCR) after the gas turbine (Liinanki and Karlsson, 1994).

• The heavy metal content in bottom- and fly ash is very low. The content of

cadmium was about 1 ppmw and of mercury about 0,01 ppmw.

• The results from the test shows that the concept works well with expected performance. The gasifier has a high carbon conversion rate (>98 %) and performs a good gas quality (LHV = 4-6 MJ/Nm3) suitable for gas turbine combustion (Liinanki and Karlsson, 1994).

The VEGA project was a pre-engineering study for a pressurized, air-blown bio-IGCC of 140 MWfuel located in Eskilstuna. It never became reality because of the high investments costs (20 300 SEK/kWe, 1995 cost level). In the end of 1980 Vattenfall started a pre-engineering study to develop biomass gasification (CFBG) and gas cleaning technology for the purpose of power and district heat generation via a large turbo charged diesel engine developed by Hedemora Diesel. The project was in cooperation with Studsvik Energy (TPS), Statens Energiverk, Hedemora Diesel & Energi AB and Svensk Energiutveckling (Waldheim and Blackadder, 1990). The tests were done on a 2 MWfuel, biomass feeded, atmospheric air-blown CFBG, developed by Studsvik Energy. A catalytic cracker and scrubber technology was integrated for gas cleaning and a 500 kW diesel engine was used for electricity production. The purpose was to investigate the performance of the gasification technology and to demonstrate the possibility of tar cracking with dolomite catalyst in a circulating fluid bed, and to demonstrate the possibility to run a diesel engine on low calorific gas. The result of the program was 1300 hours of gasifier operation of which the motor was operated for 700 hours (Waldheim and Blackadder, 1990). The over-all conclusions of the activities were that:


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• The gasification process is sufficiently reliable in operation to be able to scale -

up although improvement possibilities in terms of tar reduction have been identified (Waldheim and Blackadder, 1990).

• The motor behaves as expected in terms of performance but emissions of

carbon monoxide and hydrocarbons are unacceptably high by Swedish standards, whereas emissions of nitrogen oxides are low (Waldheim and Blackadder, 1990).


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5 Gas cleaning and processing techniques There will always be a need for gas cleaning and processing to meet the demands of the end-user (gas turbines/motors, synthetic fuel production, fuel cells etc.) (Olofsson et al., 2005). The only exception is when the product gas will be direct fired in a boiler without any gas cleaning and only slightly lowered in temperature (see chapter 6.2 about Kymijärvi and Ruien power plant). The need for effectively gas cleaning and processing is therefore depending on the technical application for the product gas. A simple schematic is shown in Figure 14.

Figure 14 Schematic of integrated biomass gasification system (van der Drift and Pels,

2004).

From an environmental point of view and to avoid the plant to be classified as a waste-fired plant, the product gas has to be clean and not contain components that cause more environmental hazard in the following combustion step. The components of most interest, which causing an environmental hazard, are heavy metals, chlorine- and sulphur compounds. Also ammonia can give undesired emissions. Problems and cleanup methods are shown in Table 4.

5.1 Gas cleaning

There is roughly three ways to go when processing product gas, cooling the gas, wet gas scrubbing or hot gas filtration. The technology to be recommended is depending of what the product gas is applied for, what kind of fuel being used and type of gasifier. In hot gas filtration the gases is partially cooled to around 400°C to condense alkali metal- and heavy metal vapors onto particles in the gas. At these temperatures, the tars are kept above the condensation temperature. A hot gas filter for removal of particles, char and the condensed alkali- and heavy metals is followed after the cooling section. This minimizes the risk for alkali-corrosion in the following process.


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The advantage of this method is that the tar content is kept in the gaseous phase and can after gas processing be burned in a boiler/gas turbine without any energy losses for tar removal. Gas processing with only a slight cooling of the gas (100°C) without any further gas cleaning can be a way to go when using clean or derived fuels. However, this application can only be applied to indirect combustion in boilers since gas cleaning is necessary for gas turbines and gas engines to avoid problems with corrosion and fouling. One disadvantages with this method is the mixing of biomass- and coal ashes. Wet gas scrubbing takes place at temperatures below 200°C. After cooling, the wet scrubber removes tars, particles, char, alkali metals and ammonia (Bridgwater et al., 2002). If wet scrubbing is used then it is usual to implement thermal or catalytic cracking of the tars before gas cleaning to produce non-condensable hydrocarbon gases and so remain the chemical energy in the fuel gas. By lowering the temperature from 800°C to 50°C, 10-15 % of the energy in the product gas is released by sensible heat (Karlsson, 2008). This energy can be used for steam production, preheating the gasification air, dry the feedstock or for district heat production. Wet gas scrubbing is the way to go when the gas is being used for gas engine electricity production, since the fuel gas has to be cooled before injection in the engine. To increase the energy content of the gas, the product gas is boosted before injected to the engines. This requires a lowering in temperature to prevent energy losses from the compressor (LT-gas consumes less energy than HT-gas). The scrubber technology is more established and the product gas may be better cleaned than hot gas cleanup, but investment costs are roughly 50 % higher (Wilén et al., 2004).

Table 4 Product gas contaminants: Problems and cleanup processes (Belgiorno et al.,

2002).

Contaminants Range (g/Nm3) Examples Problems Cleanup method

Particles 3-70 Ash, char, bed material

Erosion, emission

Filtration, scrubbing

Alkali metals Sodium, potassium

Hot corrosion Condensation, filtration

Fuel nitrogen 1,5-3,0 NH3, HCN NOx formation Scrubbing, SNR, SCR (after combustion)

Tars 10-100 Aromatic hydrocarbons

Clog filters, deposits

Tar cracking, scrubbing

Sulphur, chlorine

2,5-3,5 H2S, HCl Corrosion, emission

Lime scrubbing, filtration + sorbent injection


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5.2 Particles

Particles in the product gas can be separated via cyclones, hot gas filters, textile filters, wet scrubbers and electrostatic precipitators. Removal via cyclones is based on rapidly change in gas direction, causing the particles to collide with the cyclone wall and fall to the bottom and is thereafter either recycled to the bed (CFB) or removed as ash (BFB). The pressure drop is high and cyclones can only separate large particles (>1 µm), while small particles and aerosols need further techniques for separation from the gas. The principle of hot gas filters is that the particles that passed the cyclone later can be captured in the filter, which works in a temperature of 400-500°C. At these temperatures vaporized alkali condense on the particles in the gas and can therefore be removed. Some heavy metals can also condense and be removed. Two types of hot gas filters can be observed as most used, ceramic and sintered metal barrier hot gas filters. These filters can withstand temperatures up to 900°C and 500°C respectively (Jonsson, 2006). The advantage with hot gas cleaning is the avoidance of high exergy losses due to the sensible heat released when the temperature drops (wet gas cleaning). This is of importance in IGCC and co-firing applications, but unnecessary for gas engines since the gas has to be cooled before injection. VTT has proven a ceramic bag filter for co-firing gasified waste fuels, which seems to work with excellent results regarding to chloride and heavy metal capture (see Lahti chap. 6.2.1). Separation of particles via textile filters in a temperature range of 400-450°C is also an effectively way to remove condensing volatiles. At these temperatures the vaporized tars are kept above dew point, but the temperature should not be lower to avoid any condensation of the tars. In an electrostatic precipitator, the particles in the gas are negatively charged by electrons and collected on positively charged electrodes (Jonsson, 2006). The principle can be based on both dry and wet technology. In the first option, vibrations or gas streams clean the electrodes. Wet ESPs are often used after a wet scrubber and can remove small particles and even aerosols from the gas. ESPs have high particulate removal efficiencies and low electricity consumption, but are large and expensive (Jonsson, 2006).

5.3 Tars

Tar is one of the critical classes of compounds that have to be removed before further treatment of the product gas, if the gas temperature will be lowered below 300-400°C. Depending on the choice of gasifier, the tar content in the product gas vary significantly and for some application tar content is very low and cracking is not


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necessary (EF gasifier, downdraft gasifier) but after other gasifiers it is a must. Cracking of tar is a must if the gas is supposed to be cooled (<350°C) in some step before final combustion, but not necessary if the product gas can be kept above the condensation temperature of tars. The nomenclature of tar is not well defined in literature but in gasification it is often summarized to all aromatic and Polyaromatic hydrocarbons (PAH) above benzene (78 < Mtarcomp < 300) and having a boiling point over 80°C (Olofsson, 2005). Depending on the concentration and compounds, the tar condensates at different temperatures on inner surfaces or forms aerosols. It is not only the concentration of the tars that is critical, rather the dew point temperature for the particular tar composition (Olofsson et al, 2005). For CFB gasification the tar dew point is estimated to be at 350°C (van der Drift and Pels, 2004). Tars can be removed either by thermal cracking or catalytic cracking. Other opportunities is by cooling the gas to temperature above 100 °C and remove the tar via scrubbers using special oils that absorb the tar, or in a conventional wet scrubber (Jonsson, 2006). However, this alternative generates large amount of waste condensates that has to be further cleaned before removal to recipient. It is also lowering the product gas heating value because of the combustible tar removal. In the Netherlands, ECN is using a system called OLGA for tar removal. The OLGA system is based on conventional scrubber technology with special oils for tar absorption. All light and heavy tar components, aerosols and most of the BTX (benzene, toluene and xylene) can be removed and the condensate can either be co-gasified in the gasifier or further handled. ECN has compared the technology to other concepts and stated following results in Figure 15 (ECN, 2008):

Figure 15 OLGA system compared with conventional gas cleaning based on wet

scrubbing and on a wet cleaning with an ESP (ECN, 2008).


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5.3.1 Thermal tar cracking

Thermal cracking requires a higher temperature (1100°C) than catalytic cracking (900°C), for tar removal. This results in a higher air/O2 demand for the gasifier, which increases the energy consumption, and an increased need for further cooling before the gas cleaning (Jonsson, 2006). The entrained flow gasifiers normally have operating temperatures higher than this and thus generates extremely low contents of tars (Nordin, 2008).

5.3.2 Catalytic tar cracking

The alternative to thermal tar cracking is catalytic tar cracking around 900°C. The catalytic cracking process eliminates the problem with high-energy loss and also reduces problem with clogging in scrubbers, compressors etc. Catalytic tar cracking with dolomite is one method that has seemed to be an effectively way of tar removal, see Figure 16 (Padban et al., 2002). Tar cracking with nickel-based catalysts does also exist and the technology is used at the CHP demonstration plants of Kokemäki and Skive.

Figure 16 Schematic description of an integrated gasification/combustion process with

catalytic tar cracking (TPS technology) (Padban et al., 2002).

5.4 Alkali and chlorine

A significant part of the chlorine content in the fuel can be captured in the fly and bottom ash as alkali-chlorides (Nordin, 2008). The rest of the chlorine will mainly form to HCl. Biomass includes large amount of potassium and sodium, which can react with the content of chlorine and cause fouling and corrosion problem especially in the convection zones, but also on blades in gas turbines. By removing the chlorine in the gas cleaning, this problem can be reduced drastically. Also by adding additives (peat, coal), the alkali-chlorine contents can be reduced effectively. When the molar ratio of S/Cl is higher than 4, the fuel can be said to be non-corrosive (Berg et al., 2005). However, this approach is valid for combustion behavior and is therefore only of interest in co-combustion of gasified biomass with coal.


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Some types of coal naturally contain large amounts of sulphur, which has a positive impact when co-firing gasified biomass with high alkali content, resulting in less formatting of high-corrosive alkali chlorides component. The principal is that SO2,

formed from sulphur in coal, react with alkali to form alkali sulfates, which are significantly less corrosive. Vattenfall AB owns a patent called Chlorout, which effectively can reduce corrosion and fouling problems in convection zones. The Chlorout-concept is based on injection of a sulphur-based solution before the superheating section.

5.5 Treatment of by-products

Bottom- and fly ash and process water is by-products from a gasification plant that has to be further treated before it can be deposed or further used. Unburned material is not allowed to exceed 3 % for the bottom-ash (Padban et al, 2002). The fly ash from a gasification plant does usually contain a large amount of unburned material and can therefore need extra treatment even if the purpose is to deposit the ash. Before release the process water to the wastewater treatment plant, the quality of the water must be fulfilled according to the EU directives for water emissions from power plants (Padban et al., 2002).


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6 Gasification plants of interest on the market today

This report is focused on gasification of biomass for heat and power production. There are principally three more or less established technologies for this purpose:

• Gas engine application. The produced gas is cooled and cleaned and thereafter burnt in a gas engine for CHP production.

• Gas turbine application. The produced gas is partly cooled and cleaned and burnt in a gas turbine integrated with a steam cycle (IGCC).

• Co-firing in a boiler. The produced gas is cooled/partly cooled and cleaned/un-cleaned and thereafter burnt in a boiler (Rankine cycle).

However, as discussed before, bio – IGCC technology still has to be further developed and economical feasible before it can be applied in large scale for power production. It is therefore not deeper investigated in this report. Some of the gasification units on the market are listed in Table 5.

Table 5 Some of the gasification plants on the market.

Plant name Location Gasifier supplier

Gasif. type

Press.

Gasif.

agent

Appli-

cation

Size (MW)

Fuel Year Costs

ESSENT/

Amercentrale 9

Geertruiden-berg, the Netherlands

Lurgi CFB Atm. Air Cofiring in PC boiler

85 MW th

Demolition wood

2004 1300 €/kWe

Kymijärvi power plant

Kymijärvi, Lahti, Finland

FW CFB Atm. Air Cofiring in PC boiler

45-70 MW th

Wood, REF, paper, plastics

1998 12 M€

Electrabel power plant

Ruien, Belgium

FW CFB Atm. Air Cofiring in PC boiler

50-86 MW th

Fresh wood, bark, board residues

2003 Similar to Lahti

Biococomb* Zeltweg, Austria

Austrian Energy

FB Atm. Air Cofiring in PC boiler

10 MW th

Bark, sawdust, woodchips

1997 5,1 M€

McNeil generating station *

Burlington, USA

FERCO Indirect CFB

Atm. H2O & air

Cofiring in boiler

40 MW th

Woodchips, waste wood

1998 11-12 M$

Greve in Chianti

Greve in Chianti, Italia

TPS CFB Atm. Air Cofiring in boiler

30 MW th

RDF pellets 1992

* Not in operation today.


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Pöls paper mill

Pöls, Austria

Lurgi CFB Atm. Air Firing in boiler

35 MW th

Bark 1987

Rüdersdorfer zement GmbH

Rüdersdorf, Germany

Lurgi CFB Atm. Air Firing in boiler

100 MW th

RDF 1996

Värö pulp mill

Värö, Sweden

Kvaerner/

Götaverken

CFB Atm. Air Lime kiln fuel

30 MW th

Bark, wood waste

1987

Corenso United Ltd

Varkaus, Finland

FW BFB Atm. Air Lime kiln fuel

40 MW th

Aluminous plastic waste

2001 10 M$

Norrsundet Bruk AB

Norrsundet, Sweden

FW CFB Atm. Air Lime kiln fuel

25 MW th

Bark 1984

ASSI Karlsborg

Karlsborg, Sweden

FW CFB Atm. Air Lime kiln fuel

27 MW th

Bark 1984

Güssing power plant

Güssing, Austria

Babcock borsig power &AE

Indirect CFB

Atm. H2O

& air

CHP with gas engine

8 MW fuel

Mainly woodchips

2002 10,7 M€

Skive power plant

Skive, Denmark

Carbona BFB 2 bar

H2O

& air

CHP with gas engine

17 MW th

Wood pellets

2007 185 MDKK

Kokemäki power planta

Kokemäki, Finland

Condens Oy & VTT

Updraft

gasifier

Atm. Air CHP with gas engine

4,3 MW th

Sawdust, woodchips, bark

2006 5 M€

Harboøre Harboøre, Denmark

Babcock Wilcox Vølund

Updraft

gasifier

Atm. Air CHP with gas engine

4,8 MW th

Biomass 1994

Freiberg Freiberg, Germany

CHOREN

GmbH

EF 5-30

bar

O2 Gas engine and FT-fuel

30 MW th

Wood waste

2007

Värnamo* Värnamo, Sweden

FW & Sydkraft

CFB 33 bar

Air Bio-IGCC 15 MW th

Wood chips 1993 46 kSEK

/kWe

ARBRE* Eggborough, Yorkshire, UK

TPS AB CFB Atm. Air Bio-IGCC 28 MW th

Forest residues

2002

Puertollano Puertollano, Spain

Krupp Uhde EF

25 bar

O2 Coal-IGCC

320 MWe

Coal and petroleum coke

1998 1,3 k€

/kWe

(SEP/ Demkolec) Nuon Buggenum

Buggenum, the Netherlands

Shell EF

O2 Coal-IGCC

250 MWe, 600 MW th

Coal and 30 % biomass

1993 1,1 k€

/kWe

a Not in operation under 2008 because of contract contention. * Not in operation today. * Not in operation today.


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PSI/DESTEC Wabash river

Wabash river, USA

DESTEC EF 27 bar

O2 Coal-IGCC

262 MWe

Coal 1995

Tampa Electric

Polk county, USA

Texaco EF O2 Coal-IGCC

250 MWe

Coal 1996

Freiberg, Schwarze Pumpe

Freiberg, Germany

Future Energy (Siemens)

EF 25 bar

O2 Oil-IGCC 130 MW th

Waste oil, slurries

1984

Nippon Petroleum Refining CO

Negishi, Yokohama, Japan

CHEVRON /Texaco

EF O2 Coal- IGCC

433 MWe

Coal 2003

6.1 Gasification with gas engine for heat and power production

Gasification of biomass and gas cleaning technology for power and district heating via gas engines is one promising alternative way to go. For small-scale CHP production, gasification with gas engine has an advantage compared to traditional combustion (Rankine-cycle) plants, since the electricity efficiency is considerably higher. Recent years, much research and development has been done and some small-scale demonstration plants have been built. These types of plants are in the range of 2-20 MWth, atmospheric, air-blown, and most of them use GE Jenbacher gas engines for power production. Updraft, indirect-FB and single FB gasifier seems to be the most common application. Most of the technologies have some kind of tar removal followed by product gas cooling and filtering and finally water/or-and oil scrubbers.

6.1.1 Güssing power plant

The plant in Güssing, owned by the Austrian company Repotec and built by Babcock borsig power and Austrian Energy, is an 8 MWfuel, CHP plant with a 2 MWe gas engine for electricity production and 4,5 MWth for district heating. The fluidized bed gasifier consists of two zones, a gasification zone and a combustion zone, see Figure 17. The gasification zone is fluidized with hot steam, which is generated in the gas cooling section. The syngas will therefore be almost completely nitrogen free. The gas is reported to have a calorific value of over 12 MJ/Nm3

dry (Renet, 2008). The combustion zone is fluidized with air and delivers the heat generated to the gasifier via transportation of the bed material.


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Figure 17 Simple schematic illustration of indirect gasification technology (Rauch, R).

The produced gas is cooled by water heat exchangers, which reduce the temperature from 850-900°C to 140-150°C. The first cleaning step is a fabric filter for removal of particles and some of the tars. These particles are returned to the combustion zones of the gasifier. After that, a scrubber section removes the rest of the tar and also ammonia, and the produced condensate with saturated tar is fed into the combustor. By scrubbing, the temperature of the gases reduces to about 40°C, which is necessary for the gas engine. The cleaned gas is compressed and finally fed to the GE Jenbacher gas engine for production of electricity. The results, reported by RENET, have mainly been satisfied since continuous operation started. The availability of the gasifier and the gas engine has been reported to be successful and grows yearly due to experience and new technology breakthrough. The gasifier has been in operation for 36 400 hours and the engine for 31 700 hours by the first of March 2008. The availability for the gasifier is reported to be around 90 % (Held and Karlsson., 2008). Process diagram is shown in Figure 18. The plant is a small-scale demonstration plant with advanced technology and is therefore quite expensive. The total investment cost was calculated to 10,7 MEUR (2000) and the yearly operation cost is about 10-15 % of the total investment cost. For a second similar unit, 25 % reduction of investment cost can be expected due to the experience and learning from the demonstration plant (BIO-CHP, 2008)). Much research and development for liquid fuels and SNG production is going on and the twin bed gasifier technology seems to be most suited for these applications and not for cost effective CHP production. For this purpose, it seems that Göteborg Energi will built a 20 MW demonstration plant, with twin-bed technology, for methane production in 2011 (GoBiGas project).


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Figure 18 Process flow sheet for the gasification CHP plant (Rauch, R).

6.1.2 Skive power plant

At Skive, Denmark, the Finnish/American Company Carbona Corporation has recently built a biomass CHP plant for power production and district heating. The unit is still under test operation and only one engine is installed. Fully continuous operation is expected to be in a near future. The fuels in use are wood pellets. The plant will be delivering 5,5 MWe, by three JMS620GS GE Jenbacher gas engines and deliver 11,5 MWth of district heating to the citizens in Skive. The gasifier is based on low- pressure (2 bar, can be varying between 1-3 bar depending on load conditions), fluidized bed (BFB) technology with a cyclone and uses steam and air as gasification medium and has dry ash removal. After the cyclone, a catalytic tar-cracking unit is connected followed by gas cooling and gas cleaning, see Figure 19. The tar cracking is based on the novel tar cracking/reforming system, which has been developed and tested together with VTT in pilot plant and also at the demonstration biomass gasification plant in Kokemäki, Finland. The catalytic cracker operates at 900 °C and uses a nickel-based catalyst that converts tars and ammonia to CO, H2O and N2. To compensate for the endothermic reaction, some of the gas from the gasifier is combusted (Jonsson, 2006). After the tar cracking, the gas is partly cooled, by district heating water, and the remaining dust and particles are captured in a bag filter unit. The gas is scrubbed and thereafter combusted in the gas engines or in a separated boiler for heat production (Salo, 2005). The design product gas has an LHV of 5,5 MJ/Nm3 and the composition of the gas is presented in Table 6.

Table 6 The product gas design composition are as followed (vol-% and vol-ppm)

(Jonsson, 2006).

Component N2 CO CO2 H2 H2O CH4 CxHy H2S+COS NH3+HCN HCl

42% 23% 10% 21% 3% 1% 20ppmv 80ppmv 50ppmv 30ppmv


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By cooling the product gas, engine and the exhaust gases, district-heating water is produced for approx. 70 % of the citizens in Skive. The produced gas can also be flared in case of problems with the engines or/and the boiler. The plant in Skive cost approximately 185 MDKK to built and is expected to have a technical lifetime of 15 years (Scott, 2007).

Figure 19 Process scheme of the BGGE plant in Skive, Denmark.

6.1.3 Kokemäki power plant

Condens Oy has together with VTT developed a Novel gasification process, Figure 20, that combines updraft gasifier with catalytic gas cleaning process to produce a product gas suitable for gas engines. The fuel in use is biomass residues and energy crops and the gasifier size is in order of 7 MWth. The feedstock is dried to about 20 % moisture by using low-temperature waste heat from the plant and fed at the top of the gasifier. The produced gas is cleaned by a tar reformer, cooled and scrubbed in a wet scrubber, boost and injected in the three turbocharged 0,6 MWe GE Jenbacher gas engines to produce 1,8 MWe power and 4,3 MWth for district heating.

For the moment, only one engine is in operation and the other two will be installed in the end of 2008. This technology enables the possibility to produce electricity over two times higher to that of steam cycles in the same size (Hannula et al., 2007). One other advantage is the relative cheap technology (e.g. gasifier), since traditional fluidized bed gasification are not economical suitable for small scale plants due to their high investments costs. The updraft gasification technology is however limited to CHP plants below 20 MWfuel. Results from the tests showed that all the basic hardware of the process seemed to be working well and as expected. Continuous production of clean, tar free product gas that fulfills the engines requirements has been achieved. The system automation has come to a level, where un-manned operation is possible under steady state operations (Hannula et al., 2007). Even if continuous operation of gas without condensable tars has been fulfilled under steady state operations, it has been shown that quick changes in the process parameters (fuel moisture variations, engine start-ups etc.) can cause tar


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peaks that have a tendency to accumulate on the end-cooling equipments. The fluctuations in the need of district heat are a problem that has to be further developed, since this varying demand interrupts the steady-state operation and therefore also the gas processing and power production (Hannula et al., 2007). This may be reduced by install a thermal storage unit. The advantage of this concept is the higher electrical efficiency compared with Rankine cycles for small-scale CHP production. Even if the investment cost is higher for BMG CHP plants, the payoff time could be shorter because of the higher electrical interchange. Total investment cost for the Kokemäki BMG CHP plant was 5 MEUR (Hannula et al., 2007).

Figure 20 The NOVEL BMG CHP system (Babu, 2006).


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6.2 Gasification for co-firing in a boiler for heat and power production

Biomass co-firing gasification technology had its real breakthrough in the early 1980’s, when the oil prices started to increase. The gasifiers where installed at several paper mills to provide heat to lime kilns and is still today in work at some places. Gasification of fuels for co-firing makes it possible to use waste derived fuels and biomass residues for co-combustion in large fossil fuel fired plants. Biomass combustion technology is today mostly limited to small and medium scale application for heat/heat and power production and is often related with high capital costs. Due to the low bulk density, bio-fuels are economically only locally within a close transportation distance and are therefore used in small to medium sized plants. The disadvantages with these plants are that they are working with relative low electrical efficiency, minimizing effectively use of the renewable resources. Conventional steam based, biomass Rankine cycles cannot compete with the efficiency of large coal power plants. Combining the bio-fuel plant to an existing power plant will increase the viability of biomass utilization. One way to effectively improve the biomass use is therefore to combust it in existing boilers with higher steam data. This is already done with direct co-firing in many boilers today with clean, high quality biomass. However, there is only a couple of percentage of biomass in use at these plants and the price for the clean biomass is often more expensive than coal. Current experience indicates that direct co-firing is possible up to 5-10 % of the calorific value of the coal input. Along with increasing input of biomass, the issue of ash from the combustion process gains significant (Maciejewska et al., 2006). The case of mixed biomass and coal ashes is often problematic. The ashes from direct co-firing units are neither appropriate for single biomass ash applications, nor are they appropriate to be utilized in the same applications as for single coal ash (cement and concrete production). The problems associated with mixing biomass ash with coal ash is mostly the alkali content in the biomass, which have a negative impact on the concrete properties made from coal ash. They may react to flint stone particles in the gravel aggregate, with which the cement is mixed during concrete manufacturing. This can result in absorption of water leading to volume expansion, formation of cracks made from freezing and thawing. This in turn leads to a limited usage of the ash and the only solution may be deposition as landfills (Kavalov and Peteves, 2004). Biomass utilization via direct co-combustion in large PC boilers may also be impossible due to political directives. As an example, for gypsum produced in the flue gas cleaning, the chlorine content has a maximum allowableness in Germany. This limits the usage of biomass in co-firing to only a couple of percent (Karlsson, 2008). Problems with the feeding system and the milling of biomass together with coal is often reported to limit the biomass input to the boiler. However, this can be overcome by have a separate line for biomass pre-treatment and feeding, but will also increase the investment costs.


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By increasing the co-firing ratio and expand the range of biomass fuels may not only have a positive environmental effect but also reducing the operational costs for the power plant (less fuel costs, no costs for CO2 quotas, subsidies for RE-fuels). Indirect combustion technology enables the utilization of larger proportions of biomass or waste to be combusted in a coal-fired boiler compared to direct combustion (Veijonen et al., 2003) and also enables the possibility to use more complex and contaminated fuels than for direct co-firing with biomass. Separation of aggressive component and biomass ash makes it possible to increase the input of biomass to the combustor. To retrofit an existing coal fired boiler with a biomass gasifier has the specific advantage of maintaining total independence from the coal handling and processing equipment. This will maintain the possible complete capacity for 100 percent coal firing as a future option and also lead to the same availability for the boiler as before the modification. The most developed and used gasification technology for indirect co-firing is FB gasification, where CFB gasifier is the most used application. FB technology is very fuel flexible, which enables utilization of wide selection of different bio-fuels as well as waste derived fuels. However, bed agglomeration is a severe problem, which may limit the fuel selection. Indirect co-firing plants in operation today are mostly connected to large pulverized coal plants. The main motive for these applications is the need to reduce emissions and to exploit available local biomass resources. Using biomass in existing coal boilers can often be more profitable than building a new 100 % biomass fired plant. Some pre-treatment of the fuel is necessary for indirect co-firing, like crushing at a maximum size of 50 mm, but heating value, density, moisture content and other characteristics can vary in a wide range (Nieminen and Karki, 2007). Biomass has a significantly lower heating value than most coals. This is, in part, due to the generally higher moisture content and due to the high oxygen content. However, the adiabatic flame temperature for dry biomass is almost the same as for coal even though their heating values differ by over 33 %. This is true for dry biomass, which says that the flame temperature is independent of the oxygen content. However, for biomass with high content of moisture, the adiabatic temperature is lower than for coal (Demirbas, 2002). Co-firing biomass enables the possibility to reduce the nitrogen oxides emissions from the plant. Re-burning technology with natural gas has been in use for a long time at coal and oil fired plants for NOx reduction. The technology is simple, some of the gas flow is added above the primary combustion zone to make a reducing surrounding where the NOx is formatted to nitrogen. A NOx reduction of 40 % or more is possible with this method (Padban et al., 2002).


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When biomass is fired/co-fired in a boiler, there will always be a risk of fouling, slagging, and corrosion. Problems may occur due to the alkali contents of some biomass fuels, which together with lower ash melting point of biomass ash, may cause slagging and fouling and corrosion of heat transfer surfaces. Slagging and fouling are deposition of ash on the radiant heat transfer surfaces in the furnace and on the convective heat exchangers after the furnace (Maciejewska et al., 2006). The chlorine content in the fuel may react with the alkali components to alkali chlorides, which can condense and cause severe problems with corrosion onto the heat exchanger. High-risk chlorine compounds are NaCl and KCl. Sulphur, which is in large amounts in coal, may have a negative effect on formation of alkali chloride, since it can react with potassium and form K2SO4 and HCl. HCl is a less harmful compound, since it condense at lower temperatures than KCl. With an S/Cl ratio of at least four, the blend could be regarded as non-corrosive (Berg et al., 2005). To minimize problems associate with biomass some kind of gas purity may be necessary. This can be done by only using derived fuels with known components or utilize extensive gas cleaning equipment. The first succession is associated with higher fuel prices and less fuel flexibility while the second is associated with higher investments cost and more complex operations, but less fuel costs. Some of the advantages with gasification co-firing technology are:

• Cost effectively CO2 reduction. • Favorable effects on power plant emissions (CO2, NOx, SO2). • Relatively low investment and operational costs. • Increasing biomass ratios can be utilized. • Cheaper, and a variety of different fuels can be utilized as feedstock, lowering

the operational costs of the plant. • No gas cleaning and cooling is required for clean biomass, which makes plant

investment minimized. • No pre-drying is required. • No severe modifications of the existing main boiler are required. • The main boiler can operate independently from the gasifier. • Less risk of slag formation in the boiler due to removal of the melting

minerals in the ash. • Most of the biomass ash is not mixed with the main ash, which makes the ash

processing unaffected for further usage. • Cheap, local produced fuels can be used as feedstock. A simple schematic picture of a co-firing plant is shown in Figure 21.


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Figure 21 CFB-gasifier connected with a pulverized coal boiler (Maniatis, 2001).

The big breakthrough for indirect co-firing has not been achieved. This is partly related to the technical barriers, but most certainly depending on economical and political barriers. Many European countries are undergoing changes in their environmental tax systems, making alternative energy system more feasible in an economic point of view. Still, there are some technical barriers to overcome: Technical barriers

• Flue gas cooling and gas cleaning. Fouling and plugging in the cooling section, and tar condensing in the cleaning system have suffered many plants.

• Increased corrosion rates of high temperature components. • Applications for the biomass ash. • The effects on the main boiler when co-firing raw fuel gas. Slagging and

fouling of biomass ash, corrosion of chlorine or heavy metals, NOx formation, etc.

• Fly ash utilization. • Infrastructure of biomass to the power plant. • Emissions and its effect on flue gas treatment system. There has been shown

that co-firing with biomass results in significant deactivation of SCR catalysts. The reasons for this are not definitive, but analyses confirm that alkali and alkaline earth metals are significant poisons to vanadium-based catalysts (NETBIOCOF, 2006).


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6.2.1 Kymijärvi power plant

The Kymijärvi power plant located, in the Finnish city Lahti, was originally commissioned in 1976 as a heavy oil-fired unit, but in 1982 it was modified for pulverized coal firing (Granatstein, 2002). Steam production is 125 kg/s at 540°C/170/40 bar and maximum output is 185 MWe and 260 MWth, which is served to the national electricity grid and as district heating for the citizens in Lahti. The unit operates about 7000 h/a, and is usually shut down during the high summer season. The plant also has a natural gas-fired gas turbine in use when heating demand is low. In 1998, an atmospheric air-blown CFB gasifier was connected to the plant, delivered by Foster Wheeler, and provided low-calorific gas to the coal boiler, see Figure 23. The aim of the Lahti gasification project was to demonstrate direct gasification of wet bio-fuels and the use of hot, raw and low-calorific gas directly combusted in the existing coal-fired boiler. The gasifier is fed by wet bio-fuels like, wood, REF (from households and industry), uncontaminated waste wood, peat, etc. (Figure 22) (Granatstein, 2002), with only crushing (in two rotating crushers) and a magnetic separator as pre treatment and without any drying of the fuel. Sometimes dolomite is added in the gasifier depending on the fuel in use.

Figure 22 The fuel used and the energy produced in the Lahti gasifier 1998-2007 (Takala,

2008-04-21).

On a annual basis, biomass substitutes for about 15 % of the total energy input to the boiler and varying between 45-70 MWth depending on the composition and moisture content of the feedstock (Granatstein, 2002). The raw fuel gas is directly combusted (at 750°C) - without any fuel gas cleanup and after pre-heating of the gasification air- in specially designed (low-calorific) gas burners in the boiler. The product gas main components are as followed (Table 7).


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Table 7 Product gas main components.

Component CO2 CO H2 CxOy N2 H2O

Average % 12,9 4,6 5,9 3,4 40,2 33,0

The product gas heating value is approximately between 2-3,5 MJ/kg (LHV). The availability for the gasifier is reported to be 97,5 % on a four-year basis (1998: 99,3 % 1999: 98,9 % 2000: 97,1 % 2001: 96,1 %). The total availability for the whole plant was estimated to 86,6 % under these years. No calculation for availability has been done since 2001 (Palonen et al., 2006). The electricity and district heating efficiency was reduced from 31,3 % and 49,9 % to 31,1 % and 49,4 % (HHV basis) mostly due to the high moisture content of the biomass (Granatstein, 2002). The effects on the main boiler caused by the gasifier were studied during a one-year monitoring program and are shown in Table 8a. The effects on the boiler after this year are shown in Table 8b.

Table 8 a Effects of the gasifier on main boiler emissions under one year (Palonen et al.,

2006).


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Table 8 b Emission report from Kymijärvi power plant (Kivelä, 2007).

The driving force behind the project is its positive impact on the environment by lowering the carbon dioxide emissions. It also cuts SO2 and NOx emissions. Much of the cut in the SO2 emissions is due to the lower content of sulphur in the biomass. The boiler is provided with flue gas recirculation and staged burners combustion to cut NOx emissions. The cooling effect of the low calorific, high-moisture product gas in the bottom part of the boiler also helps reduce the amount of formatting thermal NOx emissions. Total capital cost for the gasifier project was about 12 MEUR (1998) (Granatstein, 2002). This included fuel preparation, civil works, the gasifier, instrumentation and control, electrification, and modification to the main boiler. The gasifier costs was estimated to 8 MEUR and the fuel receiving system, feeding and control system costs was approx. 4 MEUR. Operational and maintenance costs was approx. 0,5 MEUR/year, where fuel handling was about 0,2 MEUR/year, gasifier about 62000 EUR/year, bed material approx. 0,1 MEUR/year and ash handling 30000 EUR/year (Järvinen, 2002). The payoff time was 8 years (Kurkela, 2008). There has been reported that Foster Wheeler will charge a higher price for a second unit (Granatstein, 2002).


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Figure 23 Cross-section of Lahti gasifier and the connection to the main boiler

(Granatstein, 2002).

6.2.2.1 The Lahti stand alone 160 MWth gasification plant case

After the successfulness with the CFBG project and installation in Lahti, Foster Wheeler and Lahti Energia have started a project to built a completely new CHP plant in the Kymijärvi power plant area in Lahti. The process is based on CFB gasification with gas cooling and hot gas cleaning based on gas filtration. The cleaned product gas is combusted in a gas-fired boiler and the flue gases are additionally cleaned in a bag-house-type filter before the stack. Several tests have been done in pilot plant to confirm the effectiveness of the cooling and filtering system. Besides pilot plant tests performed at FW’s Karhula R&D Center with gas cleaning, long-term testing has been done with slipstream equipment at the Lahti gasification plant. For 3 300 hours, 5 % of the product gas has been separated and cooled and cleaned by filters in a temperature range of 320°C-400°C. Most of the heavy metals were in solid phase at the filtration temperature and can therefore be captured in the filter. Mercury, which has a low condensation temperature, passes the filter in gas phase and need extra processing to remove. To overcome the pressure drop over the filter, the gasifier is supposed to work with a 0,1 bar overpressure (at freeboard). The limit values, set by EU’s WID, of heavy metals, dioxins and furans were easily met. Above 95 % of the chlorine content was captured (Figure 24), both by the adding of dolomite in the gasifier and also by adding calcium hydroxide before the filter (Palonen et al., 2006). Different filter elements were tested under the period: 3M’s glass fiber bag filters with ceramic coating and rigid low-density candle filter elements supplied by Tenmat


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(calcium silicate) and Madison Filter (aluminum silicate). The separation efficiency of the filters was excellent, with dust content below 10 mg/Nm3. None of the tested elements of any type failed in service, and also after the testing, all elements were found to be intact (Palonen et al., 2006).

Figure 24 Results from the gas cleaning tests with a bag filter at the Lahti gasification

plant (Kurkela, 2008 and Lahtistreams, 2007).

The fuel in use is a mixture of industrial based RDF and sorted waste from households. The plant consist of a waste fuel reception and storage station, two separate gasification lines, each consist of a 80 MWth gasifier, product gas cooler and hot product gas filter (with sorbent feeding), one common gas-fired boiler and a steam turbine, see Figure 25. A bag house filter will be installed for additional cleaning of the flue gases after the boiler to ensure undesired emissions. The capital cost for the project is calculated to be roughly 150 MEUR (3100 EUR/kWe, %30=eη also including steam turbine and a new boiler) and the concept is currently at the negotiation and permitting phase (Palonen et al., 2006).


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Figure 25 The Foster Wheeler gasification concept for recycled fuels (Palonen et al., 2006).

6.2.2 Electrabel power plant in Ruien

After the successes of the Lahti gasifier, a second very similar gasifier was built in Ruien, Belgium (Electrabel, Ruien power plant) 2003, by Foster Wheele r. It is an air-blown atmospheric CFB gasifier connected to a 540 MWth coal fired boiler. The size is 50-86 MWth (Meijer, 2003) depending on the moisture content and is fed by wet, un-dried biomass. The fuel being used are wood chips from recycled fresh wood, bark and hard and soft board residues (Palonen et al., 2006). Pre-treatments include metal separation and chipping until wood chips dimensions falls under 15 cm (NETBIOCOF, 2006). The raw gas is, after preheating of the gasification air, direct combusted in the main boiler without any gas cleanup (similar to Lahti CHP). Specific investment costs were in the range of 500-1000 EUR/kWe (Van Dijen, 2006).

6.2.3 ESSENT power plant in Geertruidenberg

In Geertruidenberg, The Netherlands, at the AMER power plant, Lurgi has scaled up the Pöls gasifier and built an 85 MWth bio-CFB gasifier for co-firing in a 600 MWe coal-fired boiler. The concept was initially based on wet gas scrubbing gas-cleaning technology, with high fuel flexibility input. However, during commissioning of the wood gasifier it appeared that the syngas cooler was suffering from severe tar fouling problem, which lead to large operational problems for the gasifier. It appeared that the water-tube cooler fouled to such an extent that the pressure drop became too high within hours (van der Drift and Pels, 2004). Instead they changed the design for the product gas treatment to be cooled to 400-450°C (Babu, 2005). Under these conditions, most of the heavy metals (e.g. Pb and Zn) and alkali compounds condense on the entrained solids, which are later removed in a hot cyclone. The cyclone separator is estimated to operate with 65-70 % efficiency (Babu, 2005). In the present


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situation, the gas is cooled from approximately 900°C to 450°C in different sections (super heater, evaporator, economizer). Because of the modification from the origin installation, the cooling efficiency is low, but enough because of over dimensioned capacity (van der Drift and Pels, 2004). This new design greatly simplified the gas processing, but reduced the fuel flexibility of the gasifier. The approximately investment costs for the total installation was estimated to 1300 EUR/kWe (Meijer, 2003). For the moment, the operation of waste wood to the gasifier has been stopped by BVA (Besluit Verbranden Afvalstoffen). The BVA is the Dutch implementing measure of the Waste Incineration Directive (Directive 2000/76/EC, WID). According to BVA, any power plant co-firing waste products are regarded as a co-incineration plant irrespectively of the quality of the product. However, the question is if the plant is regarded as a co-incineration plant even for WID. The question is under processing at the moment (Duman and Boels, 2007).


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7 Concepts of interest based on gasification for power production

To determinate which gasification technology that seems to be of most interest for heat and power production from biomass, three case scenarios has been investigated:

• Co-firing derived fuels or fuels without high amounts of contaminants without gas cleaning in an existing plant (ex coal plant).

• Co-firing complicated fuels with high concentrations of contaminates with gas cleanup, in an existing plant (ex coal plant).

• Small-scale gasification CHP plants (gas engines) with gas cleanup and fired

with complex and cheap fuels.

7.1 Co-firing derived fuels without gas cleaning in a boiler

Co-firing gasification technology is an effectively alternative to cut down CO2 emissions from fossil fuels. The technology is based on pre-gasification of biomass and thereafter combustion of the product gas in large boilers, for example at a coal-fired power plant. By replacing up to 20 % of total coal energy supply, a large reduction in fossil CO2 emission can be reached. This method has an advantage compared to combustion of same amount biomass in a CHP plant, since the steam data and plant efficiency often are much higher at large plants and therefore the renewable energy sources are exploited more effectively. To build a new biomass fired CHP with the same capacity as a co-fired gasifier would increase the capital cost significant. This concept also has the advantage of a high overall conversion efficiency to power for the substitute fuel since no cooling of the gas is necessary. A disadvantage of this concept is that a larger part of the substitute fuel contaminates and ashes enter the main boiler, which may result in fouling/slagging problems and lowering the coal ash quality. The filter ash from coal plants is of greatest importance, since it can be sold to the concrete industry. With an increasing amount of impurities, the quality could be to low for these applications. To reduce the need of comprehensive modifications in the main boiler, the volume flow of flue gases must be similar before and after the modification. Because of the higher heating value of coal compared to biomass, this will result in a less high electrical and thermal output at the plant. This assumption is based on air-blown gasification, since this method seems to be most realistic and most cost efficient. The gasifier is based on fluidized bed technology, built and connected close to the main boiler and can use both wet and dry biomass with large content of ash. Some kind of pre-processing like crushing and drying might be necessary. The gasification


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medium is air and only a cyclone for particular and dust removal is applied. The product gas is slightly cooled for pre-heating the gasification air, see Figure 26. The feedstock could be waste wood without impurities and wood residues, both dry and wet. The avoidance of gas cleaning eliminates the possibility to use highly contaminated biomass as some kind of herbaceous and waste wood with high amounts of chlorine and heavy metals.

Figure 26 Process flow sheet for the gasification plant.

7.2 Co-firing complex fuels with gas cleaning in a boiler

Co-firing complex fuels with gas cleaning before combustion in a large boiler enables the possibilities to use a variety of different fuels. It is resulting in a less operational cost of feedstock but instead increases the investment cost for the plant because of the gas cooling and cleaning section. Waste wood and RDF with high amounts of impurities can be cleaned and co-fired in boilers with minimum risk of fouling and corrosion. This can be done without lowering the steam data required for these fuels in conventional boilers. There is roughly two ways to go when gas cleaning is utilized. The first one is based on tar cracking, cooling and wet scrubber technology. By this technology, almost all of the content of heavy metals, halogens, ammonia and alkali may be removed before combustion. Disadvantages with this concept are the relative high investment costs and the relative low overall conversion thermal efficiency to power for the substitute fuel. The low-temperature (LT) fuel gas cleanup section mainly causes these disadvantages. The other concept is based on cooling the product gas to around 400°C. Under these conditions, most of the heavy metals and alkali compounds condense on the entrained solids, which may later be removed in a hot cyclone separator or/and in a hot gas filter (Babu, 2005). Calcium hydroxide may be injected to the gas before the filter for


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binding of HCl (Kurkela, 2002). It has been shown that cooling the product gas from 800°C to 400°C is possible without having heat exchanger surface temperatures below 350°C, which is considered the minimum temperature allowed to avoid tar condensation and related fouling problems (van der Drift and Pels, 2004). The steam produced in the gas cooling section may serve as heat transfer to the feed water in the main boiler for electricity production via the steam turbine. The process flow sheet for the concept is shown in Figure 27.

Figure 27 Process flow sheet for the gasification plant.

7.3 Gasification of biomass for small scale CHP production with gas engines

Gasification of biomass with gas engines for power and heat production is still under development and no commercial plant has been constructed. Some interesting demonstration plants have been built as discussed before. The technology is based on gasification of the feedstock, cooling and cleaning of the product gas via cyclones, filters and scrubbers and thereafter boost the gas and use it in a turbocharged, intercooled, spark ignition gas engine, see Figure 28. This concept is mainly based for small scale CHP production, since the size of gas engines on market today is limited to 3-4 MW units. For larger electrical outputs, it is usual to use a number of engines in parallel, which limits the economies of scale possible with gas engines. The capital cost of the 1,2 MWe GE Jenbacher natural gas engine was quoted at 571€/kWel 2004 (Rutherford and Williamson), which indicate a relative high investment cost only for the gas engines. The promising with this technology is the possibility to increase the electrical efficiency of small scale CHP production. The


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advantage of engines compared with gas turbines is the robust construction and the higher tolerance to contaminants in the produced gas. The drawback for this method is the low electrical efficiency for large-scale heat and power production, since the efficiency of a gas engine (non natural gas-fired) is close to 30 % (Rutherford and Williamson). One way to increase the electrical efficiency may be to integrate the process with a combine cycle with steam turbine to the gas cooling section and with flue gas cooling after the engine. In reality, this process seems to be unrealistic because of the high investments related to steam cycles for small-scale plants.

Figure 28 Process flow sheet for the BGGE power plant.


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8 Final gasification concept One of Vattenfalls climate goals is to reach a 50 % reduction of CO2 emissions in 2030 compared with the base-year in 1990. At the same time, the plants in the Nordic countries will be completely CO2 neutral to 2030. This will be done with maintaining or even increase the energy production. To achieve this goal, large-scale energy production from renewable energy sources must be reality in a near future. One promising way to do this might be to use existing facilities and sites as far as possible to implement renewable energy sources. This makes co-firing an interesting alternative since the technique uses much of the already existing infrastructure and equipments. This reduces the costs drastically compared with building a “Green field power plant”. The scale of CO2 reduction may be much higher for a co-firing gasification plant compared to gas engine application, since the units are capable to handle larger amount of biomass. Gas engines are still in a small-scale range and need further development for being interesting in a large-scale perspective. Vattenfall is a European company and owns plants both in Sweden, Denmark, Finland, Germany and Poland. These plants are mostly quite large plants close to big cities providing the citizens and industry with power and heat. Many of the plants in Germany, Poland and Denmark uses coal as primary fuels, which makes them suitable for co-firing with biomass to reduce fossil CO2 emissions. There are roughly two ways to go in indirect co-firing. The first one is based on “raw” syngas combustion and the other “cleaned” syngas combustion. A list of the positive and negative effects on these kinds of applications is listed in Table 9.

Table 9 Advantages/disadvantages for gas processing in co-firing utilization.

Option Advantages Disadvantages

“Raw” syngas combustion

Tars do not have to be removed before combustion.

No exergy losses due to cooling.

Lower capital and O&M costs.

Simpler construction and operation.

Plants experiences

No separation of aggressive components before combustion.

Only clean (expensive) fuels may be used.

Great problems with corrosion and emissions can occur.

“Cleaned” syngas combustion

More fuel flexible.

More complex (and cheaper) fuels can be used safely in high-efficiency steam cycles.

Separation of harmful components before combustion.

Heavy metals and chlorine can be separated before combustion.

May need tar removal if wet cleaning is used.

More difficult technically.

Increased capital and operational costs.

Less proven technology.


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Both techniques are interesting and have different advantage. Still there have never been built a commercial gasification co-firing unit with gas cleaning equipment. Two demonstration plants have been built. The one in Geertruidenberg, that initially was designed and built to clean the gas via scrubber technology, but later was retrofit with a cold cyclone. This is not an optimal gas cleaning procedure, since small particles are impossible to capture in a cyclone. The other plant is located in Greve in Chianti, Italy. It was constructed by TPS and was using RDF as fuel. However, this facility hasn’t work optimal and is for the moment closed. But much research and development has been done around the case and Foster Wheeler seems to be the supplier in front edge with this type of technique. By the increasing demand and more actors on the biomass market, the price of clean biomass will probably raise, which make more low-graded biomass interesting for heat and power purpose. New political directives may stop gasification without cleaning to use waste-classed fuels (see appendix 1 about Kymijärvi plant), which increase the fuel costs dramatically for the plant owner. In the rest of the report, the concept of indirect co-firing will be associated with gasification of biomass with gas cleaning before combustion. After the investigation, this concept seems to be the most interesting in biomass gasification applications for cost effectively CO2 reduction. A SWOT analysis has been made and is shown in table 10.


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Table 10 Indirect co-firing SWAT analysis.

Strengths Weaknesses

Reduce emissions of GHG and other pollutants to the atmosphere (SO2, NOx).

Cost-effectively CO2 reduction method.

Cheap, local produced renewable feedstock.

Ability to use other fuel sources as input.

Biomass and coal ashes can be separated⇒ don’t affect the coal ash after-treatment.

Biomass/coal ratio can be increased compared with direct co-firing.

Difficult components can be removed before combustion.

Only small modifications in the main boiler.

Independently operation of main boiler ⇒ high availability of the plant.

Cheaper than a “Green field” biomass CHP plant (No need of boiler, turbine, generator etc.).

Much of the needed infrastructure already exists.

No commercial gas cleaning plant in operation today.

The technique is still in R&D mode.

Advanced and expensive technology, which do not have a positive effect on produced energy.

Long pay-off time.

Lowering the effect of main boiler.

Biomass is a more problematic fuel than coal.

Modification in the main boiler, which may disturb the combustion behavior.

May disturb the SCR catalyst system negatively.

Fly ash utilization.

Opportunities Threats

Increased cost of coal and decreased cost for biomass.

Subventions for renewable energy production.

New, “Green power production technology”, which may have a positive impact on peoples view of Vattenfall.

Increasing taxes for fossil CHP production.

Increasing costs of fossil CO2 emissions.

Coal prices fall back to historic levels.

Increasing prices for biomass.

Uncertainty future climate politics.

New, more effective technology breakthrough.

Ongoing changes in legislation and regulations causing uncertain economic conditions for investors.

Competitions with the wood pulp industry of the biomass, leading to increased prices for feedstock.

Reliance of bioenergy on tax benefits that can be rapidly withdrawn.

Negative attitude to new unproven technology for the operators of the plant.

Coal prices may rice to levels that make the plant unprofitable and closed.

The plant may be regarded as a co-incineration plant.


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9 Retrofit of Fynsvaerket block 7 with a gasifier for co-firing biomass

Fynsvaerket, Figure 29, is a combined heat and power plant located in Odense, Denmark, own by Vattenfall AB since 2006. The two blocks, 3 and 7, produces electricity to Fyn and district heating to the citizens in Odense. Block 3 was build in 1974, installed effect is 285 MWe and 326 MWheat at 182 bar/535°C and is fired with coal, oil and natural gas. Block 7 was build in 1991 and has an installed capacity of 360 MWe, 480 MWheat at 250 bar/540, 328 kg/s and is fired with coal and oil. At the plant area there is also a waste incineration plant with a main purpose to produce part of the district heating to the citizens in Odense. A fourth block is for the moment under construction. This plant will be a straw-fired CHP plant with a capacity of 38 MWe and 82 MWheat (with flue gas condensing) and is planned to be in continuous operation in April 2009. The cost for the plant is estimated to 750 MDKK.

Figure 29 Picture of Fynsvaerket (Karlsson, 2008).

Fynsvaerket consumes 800 000 tons coal every year, which primarily is transported by boat in loads of 10 000 tons each time. Oil is used mainly as a start-up fuel and the annual consumption is about 8000 tons. The use of natural gas is very depending of supply and price of the gas and the annual consumption fluctuates from year to year. To optimize the electricity production and by having a heat back up, there is a 75 000 m3 heat accumulator located at the plant area. Block 3 and 7 is equipped with bag filters to capture the fly ash. Block 7 also has a sulphur cleaning facility and recently, block 7 was equipped with a SCR for NOx reduction. Since block 3 is old and block 7 is equipped with more advanced flue-gas cleaning equipments, block 3 acts as a peak load boiler and block 7 as a main load


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boiler. This means that a possible candidate to retrofit with a gasifier is probably block 7. The special situation in Denmark is that coal used for heating purpose (domestic, district heating and room heating of industries) is taxed with 30,7 EUR/MWh16, from with 26,3 EUR is for energy taxes and 4,4 EUR is for CO2 taxes. For electricity production there is no tax on coal (Alakangas et al., 2007). For electricity production from renewable energy sources there is a fixed RE subsidies per MWhe. 7 years ago, the plan was to introduce a trading system with RE certificates just like Sweden. However, it never became reality. The subsidies for CHP plants in Denmark depend on the fuel in use and the size and the age of the plant. Some of the rules are as following:

• There is a tax on all fuels, excepts for biomass, used for district heating production.

• There are no taxes for any fuels for power production. • All plants with a fuel input over 20 MW participate in the CO2 trading system.

However, biomass doesn’t participate in the trading system since biomass is considered as a CO2 neutral fuel.

• The district-heating price for the customer cannot be higher than the heat production cost and the cost for alternative heat sources.

A new biomass fired gasification plant using 100 % biomass could qualify as “a special RE plant of major importance”, connected to the grid after 21 April 2004, and receive a guarantee of 0,60 DKK/kWhe for the first 10 years and 0,40 DKK/kWhe for the following 10 years. If it does not qualify as “a special RE plant of major importance”, it will be ensured a premium of 0,10 DKK/kWhe, plus the spot market price (Danish Energy Agency, 2008). The electricity prices in Denmark between 2003-2008 are shown in Figure 30. If a biomass fired gasifier is connected to a fossil fuel fired plant (coal, oil), it can qualify as “a special RE plant of major importance”, and receive subsidies for RE in combination with other fuels, if the annual RE utilization is between 10 % and 94 %. RE-based production in combination with fossil fuels is eligible for a premium of 0,26 DKK/kWhe for the first 10 years and 0,06 DKK/kWhe for the following 10 years (Danish Energy Agency, 2008). Since the gasifier is fired with biomass, no need of the awarded CO2 quotas is necessary for the electricity production from biomass. The value of this depends on the current market price for emissions rights.

16 Price in June 2005 (Alakangas et al., 2007)


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Regarding the fuel taxes, CO2 costs and subsidies for biomass, substitute some of the coal input with biomass will result in less taxes and fees and incomes from subsidies. The annual CO2 emissions for Fynsvaerket was 2,3 millions tons in 2006. Allowance allocated for Fynsvaerket under 2008-2012 is 1,33 millions tons/year (Energistyrelsen, 2008). This means that the remaining 1 million tons has to be bought on the European trading market with an expected price of 25 EUR/tonne (Hansson et al., 2007). If a biomass-fired gasifier is connected to the plant, this may result in a saving of 25 EUR/tonne CO2 produced from coal since biomass is not contributing in this system. 25 EUR/tonne CO2 is equivalent with a cost of 8,8 EUR/MWh produced from coal. With a tax of 30,8 EUR/MWhheat

17 from coal and a RE subsidies of 34,9 EUR/MWhe

18, this results in a net profit of ≈ 32,5 EUR/MWhth produced from biomass ( %40≈eη ). This means that for every MWhth that being produced from biomass, a net profit of ≈ 41,3 EUR is awarded (compared with coal). However, this value is only to be true for backpressure operation. In condensing mode, the net profit would be 22,8 EUR/MWhth.

0,00

10,00

20,00

30,00

40,00

50,00

60,00

70,00

80,00

2002-12 2004-08 2006-03 2007-11

EU

R/M

Wh

e

DK-WestDK-East

Figure 30 Electricity price in Denmark between 2003-2008 (Nordpool, 2008).

The annual biomass resources and the energy use are shown in Figure 31.

0,0

2,0

4,0

6,0

8,0

10,0

12,0

14,0

16,0

Forestresidues

Industrial by-products

Domesticfirewood

Refined woodfuels (pellets)

Straw Other biomass(biogas,willow)

TW

h ResourcesEnergy use

Figure 31 Estimated annual biomass resources and energy use in TWh in Denmark 2006 18.

17 1 EUR = 7,46 DKK 18 Values are calculated from Nikolaisen, 2006.


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Straw is a renewable energy source of great importance in Denmark and the “know-how” experience in combustion behaviour is well known. However, gasification of straw isn’t unproblematic and none commercial gasifier uses straw as feedstock. Associations with high chlorine and cadmium content, low bulk density, high ash content and low ash melting temperature makes the fuel quite problematic to fire. Gasification/combustion in fluidized beds is problematic with straw, since the ash melts already at low temperatures, which makes the bed agglomerate and collapse. Straw is the largest biomass resource in Denmark and is the most widely used for electricity and heat production. Fuel price for baled straw with transportation was 16,2 EUR/MWh in Denmark 2006 (Danish energy agency, 2008). Prices for coal (without taxes) in Denmark between 2004 and 2008 are given by Figure 32.

0,00

2,00

4,00

6,00

8,00

10,00

12,00

14,00

Oct-2003 Apr-2004 Nov-2004 May-2005 Dec-2005 Jul-2006 Jan-2007 Aug-2007 Feb-2008

EU

R/

MW

h

Figure 32 Coal price in Denmark (without taxes) in Denmark between 2004-2008 (Danish

energy agency, 2008).

In 2001, the Danish company ENERGI E2 made a design study together with FW on co-firing cleaned gasified straw at Amagervaerket. A 3 MWth pilot CFB plant was used to demonstrate the technology. The overall conclusions after the test was that the actual gasification process can be carried out without problems, i.e. without sintering of the bed material, and also that the temperature can be controlled by feeding with straw and adding air and steam. Gasification temperatures were between 800-830°C. The gas cleaning procedure with gas cooling followed by filtering in warm fabric filters was also working satisfactory (ENERGI E2, 2001).

9.1 Description of the Fynsvaerket CHP plant

Block 7 at Fynsvaerket is a once-through Benson-type unit with a capacity of 900 MWfuel, build in 1991 and equipped with sulphur cleaning and de-NOx equipment. It is mainly fired with polish guarantee (design) coal with an LHV of ca 25 MJ/kgWB. The coal is milled in 4 coal millers and each miller is connected to 4 burners. In full load operation, the coal consumption is 130 tons/hour and ca 360 MW electricity (net) is produced. The burners are located in each corner in the boiler and are tangentially


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fired with an inner “eye” of 2 meters in diameter. Between each burner stage there is possible to re-circulate some of the flue gases. The boiler is built with staged burning and even so, the NOx produced can be of 650 mg/n3m. For this reason, a catalytically de-NOx facility was built in 2007. This is a secondary measure that is quite expensive to build and to operate. Just the cost for ammonia is 5 MDKK each year. This consumption could be lowered by use the product gas for re-burning purpose. The boiler efficiency is about 94 % in CHP condition and the electrical efficiency is ca 40 %. Equivalent full load hours for 2006 (at Pe = 362 MWe) was 6155 hours (Lystbaek, 2008). Production data for block 7 2006 was 1986 GWh electricity (net) and 1991 GWh district heat. When block 8 is in continuous operation it will act as a main load to the district-heating network. With a heat capacity of 82 MW, this correspondence to a heat production of 570 GWh per year (7000 h equivalent full load hours). The straw is locally produced and transported from the whole Fyn area and the guaranteed electricity price produced from the plant is 450 DKK/MWhe for the next ten years (Lystbaek, 2008). The produced heat in block 8 will substitute the heat produced in block 7. In the calculation (chapter 10) it is assumed that the electricity and heat produced by block 7 is 2000 GWh and 1450 GWh respectively. Operational time for block 3 and 7 are shown in Table 11.

Table 11 Operational time for block 3 and block 7 for 2002-2006 (Fynsvaerket, 2007).

Year 2002 2003 2004 2005 2006

Block 3 7050 5216 2221 1553 1728

Block 7 5539 7140 7755 7108 8176

As it can be seen the operational time for block 3 is decreasing, while block 7 is increasing. This is due to the higher environmental requirements and the fact that block 7 has a more modern boiler equipped with advanced flue gas cleaning equipments. In the beginning of 2000, a test run with focus to co-fire straw in block 3 was done. 500 tons of straw was fired but the increased corrosion rate on the super-heaters made the operation stopped. Under 2001-2003, when the “mad cow disease” was acting, 100 000 tons of meat and bone was co-fired with coal in block 7. There has been investigation before of widen the range of fuels at the plant. Discussions with the neighbor to the plant, a car destruction company “HJ.Hansen”, whose specialty is recycling of materials from the process, has been investigated before. A rest-product from this process (most plastics and rubber) may be used for energy recovery. 100 000 tons of this product is expected each year. Today this product is deposit as landfill but soon there is expected to be a tax increase for this product, which indicates that prices for these fuels are supposed to decrease. The limitation of using biomass directly in the boiler is mainly caused by the lower quality of the filter ash. 99 % of the ash entering the boiler is captured as filter ash


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while the rest is as slag. The filter ash is further sold to the industry as component in concrete and cement. The requirements from these producers are high (maximum 4 % unburned carbon, fine-grained) and the price for ash to concrete is 5 times higher than for cement. The quality of the ash is therefore of greatest important for the plant owner. For more information about layout and pictures of the plant and process conditions of block 7, see appendix 3 and 4.


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10 Process study The present study is based on the following assumptions:

• The main boiler is a pulverized coal fired CHP plant. • Heating value of coal is 28 MJ/kgDS with moisture content of 9 % after drying. • Maximum fuel input is 900 MW and the boiler works with 94 % efficiency. • The average electricity efficiency is 40 %. • A CFB gasifier is connected to the boiler and works with 98 % efficiency. • 14 % of the coal input is substituted with gasified biomass. • The volume flow and the velocity of the flue gases are constant before and

after modification. • Oxygen in flue gases is constant at 3 % before and after modification. • The gasifier is a slightly over-pressurized atmospheric air-blown CFB. • The average energy produced for district heating production is 27 % of total

fuel input. • Both the gasification plant and the main unit are assumed to be in operation

for 6000 equivalent full-load hours per year. The biomass characteristics used in this modeling is listed in Table 13a.

Table 12 a Biomass characteristics used in the modeling.

Characteristics Value used Moisture content (initial) 15-45% Moisture content after drying 15% Lower heating value (dry) 19,0 MJ/kg Ultimate analysis, % of dry mass C – 50 % H – 6 % O – 41 % N – 1 % S – 0 % Ash – 2 % Size distribution 5-100 mm


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The coal characteristics are listed in table 13b.

Table 12 b Characteristics of polish coal (hard coal) used in the model.

Characteristics Value used Moisture content (after drying) 9 % Lower heating value (dry) 28 MJ/kg Lover heating value (wet) 25,2 MJ/kg Ultimate analysis, % of dry mass C – 74 % H – 4 % N – 1 % O – 7 % S – 1 % Ash – 13 % The heating value of biomass is directly related to its moisture content. When biomass is indirect co-fired in a boiler, the resulting boiler efficiency will be decreasing with a increasing of moisture content of biomass if the flue gas flow will be the same. This is, of course, because of the larger amount of inert H2O in the flue gases. So a higher heating value of biomass will end up in a less effect on boiler efficiency when co-firing is applied. The heating value is calculated from following relation (Wester, 2002) and are shown in Figure 33:

( ) FFHH DSeff ⋅−−⋅= 442,21 19 (5)

where: =effH Effective heating value (wet basis). [MJ/kg] =DSH Effective heating value (dry basis). [MJ/kg] =F Moisture content. [%]

19 2,442 MJ is the energy required to evaporate 1 kg of water at 25°C and 1 bar.


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0

2

4

6

8

10

12

14

16

18

20

0 5 10 15 20 25 30 35 40 45 50

Moisture content (%)

Hef

f [M

J/kg

]

Figure 35 Heating value of the biomass, depending on the moisture content of the

feedstock20.

Assuming that the maximum coal input is 900 MW, and the effective heating value (dry basis) of coal is 28 MJ/kg and the moisture content is 9 %21. With these assumptions we can calculate the fuel rate:

eff

inputfuelfuel

HP

m ,=•

(6)

where: fuelm•

= The fuel rate of coal [kg/s]

inputfuelP , = The maximum fuel input to the boiler [MW]

fuelm•

= 35,6 [kg/s]

Knowing the properties of coal, the stoichiometric oxygen need can be calculated assuming all coal, sulphur, oxygen (in the fuel) and hydrogen is converted to CO2, SO2 and H2O and the nitrogen in the fuel and the air exits as N2. The moisture in the fuel is assumed to evaporate and stay inert. This is done for above mentions conditions resulting in following relation:

2222

222

)5,1176,3(108271999)76,3(102314217812981999

NSOOHCONOSNOOHHC

+⋅+++→+⋅++++++

αα

(7)

Where the prefix α is the coefficient for stoichiometric combustion. Solving this equation results in an oxygen need of 2263 mole/s. Assuming an oxygen concentration of 3 % in the flue gases, the lambda value, ?, can be calculated. 20 The heating value of biomass is assumed to be 19 MJ/kg on dry basis. 21 Heff, coal = 25,2 MJ/kg


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22222

222

)5,1176,32263()1(2263108271999)76,3(2263102314217812981999

NOSOOHCONOSNOOHHC

+⋅⋅+−+++→+⋅⋅++++++

λλλ

(8)

This results in a lambda value of 1,18. Now, the total molar flow in flue gases can be calculated by assuming ideal gases properties, then the volume flow of FG can be calculated by:

PTnR

v

•• ⋅⋅

= (9)

where: =

•v Volume flow of FG [Nm3/s]

=•n Molar flow of FG [mole/s]

=R General gas constant [J/mole*K] =P Pressure at 1 atmosphere [N/m2] =T Temperature [273 K] By keeping the volume flow and the velocity of the flue gases constant, before and after gasification installation, the need for large modifications in the main boiler will be minimized. The volume flow of FG is calculated to be 301 Nm3/s for a 900 MW, fired with coal (9 % moisture content), CHP plant with 3 % oxygen in the FG. The characteristics of the coal boiler are listed in Table 13.

Table 13 Specification of a pulverized coal CHP plant with a fuel input of 900 MW.

Boiler capacity (MWfuel) 900

Fuel input (kg/s) 35,6 (900 MW)

Heating value of coal (MJ/kgWB) 25,2

Volume flow of FG (Nm3/s) 301

Volume flow of air (Nm3/s) 287

Oxygen in FG (%) 3

Lambda 1,18

Boiler efficiency (%) 93,7

Boiler power (MW th) 843

Electrical efficiency (%) 40

Operational time (full load/year) 6000

Assuming a gasifier is built close to the boiler and replacing part of the coal input by biomass and that the gasifier can treat both wet and pre-dried biomass. The energy content in the biomass is assumed to have an effective heating value of 19 MJ/kg,DS. The resulting boiler power will mostly depend on:


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1 The percental substitution of coal to biomass. The higher the percental biomass input is, the less is the main boiler power. Effective heating value is higher for coal than for biomass, resulting in a decreasing boiler effect.

2 The moisture content of the feedstock. However, the moisture content of coal

is assumed to be constant. Increasing moisture content of biomass will result in a higher concentration of evaporated water in the FG. Since the volume flow of FG is expected to be constant before and after modification, the content of moisture should be minimized with respect to increase the boiler effect.

With a coal input of 86 % of the origin case, the FG volume flow from the coal combustion is 259 Nm3/s, which result in a residual FG volume flow of 42 Nm3/s. This reduces the carbon dioxide emissions from fossil fuels with about 270 000 tons per year. Four calculations has been done with different moisture content of the biomass to see the importance of keeping the water content of biomass at low levels, Table 14.

Table 14 Specifications of the biomass and the gasifier.

Biomass Biomass Biomass Biomass

Moisture (% w) 15 25 35 45

HDS (MJ/kg,DS) 19 19 19 19

Heff (MJ/kg,wet) 15,8 14,4 12,5 9,9

Gasifier

efficiency (%)

98 98 98 98

Oxygen in FG (after main boiler) (%)

3 3 3 3

Maximum FG from biomass (Nm3/s)

42 42 42 42

Fuel input (kg/s) 7,6 8,3 9,2 10,2

Gasifier effect (MWfuel) 120 113 105 96

Total effect (gasifier + main boiler) (MW th)

835 830 822 813

Relative decrease of delivered effect (compared with 100 % coal) (%)

1,0 1,7 2,5 3,6

Reduction of fossil CO2 emissions (tons)

270 000 270 000 270 000 270 000


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As it can be seen the gasifier effect drops with an increasing moisture content in the biomass. This leads to a lower main boiler effect and the heat and power output from the plant will decrease after the modification. To calculate the energy released due cooling the gas from 825°C to 425°C, an average heating value of the gas has to be calculated. Assuming the ultimate analysis of biomass being the same as listed in table 13a and a biomass moisture content of 15 %. This correspondence to a biomass heating value of 15,8 MJ/kgWB. The product gas composition on dry basis for an atmospheric air-blown CFB gasifier is assumed to be as listed in Table 1. The specific heating values of the components in the product gas are listed in Table 15.

Table 15 Specific heating value of components in the gas (Cengel and Turner, 2005 &

Kays et al., 2004).

Component CO CO2 CH4 H2 C2 H2O N2

Cp at 850K [kJ/kgK]

1,151 1,187 4,022 14,74 1,0 2,20 1,133

With this information, an average specific heating value of the product gas can be calculated and the heat released during cooling can be calculated by eq. 10.

)( 21850@ TTmCQ gasKpcooling −⋅⋅=•

[MW] (10)

For a biomass input of 7,6 kgWB/s, and with a lambda value of 0,33, the product gas mass flow will be 20,8 kg/s (820 mole/s). Assuming ideal gas properties the volume flow can be calculated. The specific heating value Cp of the product gas is calculated to be 1,43 kJ/kg and the heat released due cooling is estimated by eq. 10 to be 11,8 MW. The percental heat released due to cooling is given by eq. 11.

%8,9098,0120

8,11≈==

input

cooling

QQ

(11)

The heat released in the cooling section may support as heat exchanger for preheating the gasification air but also for preheat the main boiler feed water. The heat needed to evaporate 1 kg of water from a typical biomass fuel can exceed 2,6 MJ (Maciejewska et al., 2006). For drying 1 kgWB/s biomass from 30 to 15 %, the heat needed will exceed 0,46 MW and with a fuel input of 120 MW, this correspondence to 3,5 MW. Preheating the gasification air from 10°C to 300°C will require:


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)( 12150,@, TTmCQ airCairpairpreheat −⋅=•

° [MW] (12)

which is calculated to be around 3,9 MW for the base case with a fuel input of 120 MW and a biomass moisture content of 15 %. The calculations can be summarized in Table 16.

Table 16 Specifications of the gasifier and the main boiler effect.

Moisture (%) 15

HDS (MJ/kg) 19

Heff, wet (MJ/kg) 15,8

Gasifier efficiency (%) 98

Product gas volume flow (Nm 3/h) 60 000-70 000

LHV gas (MJ/kg) 5,0-5,2

Oxygen in FG (after main boiler) (%) 3

Maximum FG from biomass (Nm 3/s) 42

Fuel input (kg/s) 7,6

Lambda value (gasifier) Around 0,3

Gasifier effect (MWfuel) 120

Heat released due to cooling (% of gasifier effect) 9,8

Heat released due to cooling (MW) 11,8

Total effect (gasifier + main boiler) (MW) 835

Relative decrease of delivered effect (compared with 100 % coal) (%)

1,0

Reduction of fossil CO2 emissions (tons) 270 000

At least two plants of this type are for the moment at the negotiation and permitting phase and planned to be built in a near future. The first one is the 160 MWth FW gasification plant in Kymijärvi discussed in chapter 6.2.1.1 and the other is planned by the Swedish power company Mälarenergi and located in Västerås, Sweden. This facility will be a 200 MWth gasification plant consisting of 2-3 CFB gasification lines connected to the 400 MWfuel coal-fired power plant. Some of the coal burners will be changed to large gas burners specially designed to burn low-calorific product gas. Heat energy from the cooling section will be used for pre-heating the main boiler feeding water and additives such as chalk will be injected before the bag filter working at 400-500°C. Dust and particles in the filter will be blown away using pulsing inert gas. Waste fuels will be used, such as RDF and PWP and the annual consumption is calculated to be 500 000 tons/year, transported mainly by boat from the continent. No


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wet bio-fuels will be used, which indicates that there will be no drying of the fuels. Both FW and Metso Power seem to be possible providers and they say that there s hould not be no technical problems to satisfy the requirements. By calculations, this method seems to be more economic that building a new waste power plant and the total cost for the project is estimated to 1 500 MSEK (18750 SEK/kWe, %40=eη ), including modifications of the steam boiler. This compared with prices reported in “El från nya anläggningar” of 55 500 SEK/kWe (30 MWe) seems to be an interest solution. It is unclear when the investment decision will be taken, but the plans for the project seem to have gone far (Tollin, 2008-04-18). In 2001, ENERGI E2 and Foster Wheeler carried out a test program regarding straw gasification in a 3 MWth atmospheric CFB gasifier with gas cleaning. Parallel with this, a design study was conducted with the aim to carry out conditions for a 100 MWth gasifier connected to the coal fired power plant at Amagerveaerket. Economical calculations showed that the cost for the plant would be 38,4 MEUR (960 EUR/kWe,

%40=eη ). However, high prices of straw and low prices of the district heating in Copenhagen made the project to unprofitable (ENERGI E2, 2001).


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11 Design study

11.1 Introduction

The design study covers a case with a biomass based CFB gasifier connected to a large-scale coal-fired CHP plant. The selected size is 120 MWfuel, which corresponds to an annual consumption of 160 000 tons 22 biomass. The fuel in use will be cheap biomass, containing large amount of contaminants, which makes it necessary to clean the gas before combustion. To substitute some of the coal input with biomass, the emissions of fossil CO2 can drastically be reduced. With increasing coal prices and subsidies for RE electricity production, this concept may also have a positive economical potential. The aim of the design study is to present a 120 MWth biomass based CFBG connected to a 900 MWfuel PC fired CHP plant, the required equipments and to analyze the economical feasibility of such a project. The main process diagram is shown in Figure 34.

Figure 34 Main process diagram of a gasification plant for co-combustion of biomass with

coal.

22 Calculated on 15 % moisture content in the biomass with a heating value of 19 MJ/kgDS and 6000 h/year in operation.


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11.2 Biomass storage, conveying, drying and preparation

The biomass storage facility will have a capacity corresponding to 2 days of full load condition. With a biomass delivery between 7-18 on weekdays and 7-14 Saturdays (as for Fynsvaerket, block 8), the remaining biomass on Monday morning will last for 7 more full load operational hours. Biomass from the storage will be fed with a screw conveyor to a chain conveyor system and transported to the screening station. Stones and other larger heavy particles are separated by a windscreen and are falling down in a container. After that, the fuel mix is passed through a crusher, magnetic separator and later passed through a sieving station. A chain conveyor transports the fuel to an intermediate storage, which may have a capacity of at least one day. The biomass may need to be dried to improve the efficiency of the gasifier. There are several different types of dryers to choose from and the choice depends on a number of parameters, such as bulk density, moisture content, application etc. Some biofuels may not need drying to improve the gasification efficiency, since the moisture content of the feedstock is low at origin. For example, straw that has being harvested in early spring season and upgraded biomass often contains moisture under 15 %, which make drying unnecessary. The dryer can be either direct heated by hot air, flue gases or steam or indirectly heated where the heat source is separated from the wet material. The advantage with the indirect dryer is that it is possible to recover the latent heat from evaporated water in the material. It also minimizes release of hazardous VOCs to the atmosphere. Indirect dryer also seems to be related with higher investments costs and more complex operational conditions. In direct dryers, the drying medium is in direct contact with the feedstock and the water vapor released is mixed with the drying medium. One method to increase the total efficiency of the plant may be to use the hot flue gases to dry the fuel. This is a simple and cheap drying method but can be problematic due to fires from ignition of the fuel and cleaning of the vapor is required to eliminate VOC emissions to the atmosphere. Steam dryers consist of a closed loop, where superheated steam is circulated by a fan. The steam originates from the wet material and is superheated indirectly in a heat exchanger by a heat source. The steam dries the wet material and the dry material is separated in a cyclone. The residence time is from 10 seconds to minutes depending on desirable dryness. The absence of air makes the fire risk minimized and since the process is closed, emissions to the atmosphere are avoided. 80-90 % of the energy can be recovered by this technique. Costs for a “turn key” steam dryer with an input of 20 tons dry biomass/hour is reported to be 4,5 MEUR (Münter, 2008-05-14).


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11.3 Gasification system

Cheap, locally produced biomass will be gasified in an atmospheric circulating fluidized bed gasifier. Air will be distributed slightly pressured in the bottom of the gasifier via air nozzles, and limestone and sand will be used as bed material to get the bed fluidized. Because of the fluidizing condition with high gas speeds, some of the particles will escape un-oxidized over freeboard and later be captured in the cyclone and returned through the cyclone leg back to the bed. The hot LHV gas from the gasifier flows from the gasifier cyclone through the air pre-heater. Typical fluidization air velocities for a CFB are around 5-6 m/s. With a reactor height of 30 m, this corresponds to a residence time of 6 seconds. With an increasing residence time the tar cracking process is favorable. To prevent sintering in the bed, some air might be injected in freeboard instead of inject all as primary air. By doing this, the bed temperature could be lowered, minimizing the risk of bed agglomeration. Another complement method could be using a mixture of steam and air as gasification medium to control rising gasifier temperatures. The gasifier is designed to convert 7,6 kg/s biomass with a heating value of 19 MJ/kgDS and with a moisture content of 15 %. Lambda value will be around 0,3, which result in an airflow of ca 13 kg/s. The calculated volume flow of the product gas is about 67000 Nm3/h (19 Nm3/s). With an inner diameter of 4 meters and a height of 30 meters, bed temperature of 825°C, the residence time is calculated to be 5 seconds. Dimensions of the pipes after the gasifier should satisfy the requirement of having a gas velocity between 10-15 m/s (Padban & Karlsson, 2008). With a gasflow of 75 m3/s at 825°C and a gas velocity of 15 m/s, the dimensions of the pipes should be around 2,5 meters in diameter, while at 425°C the dimensions should be around 2 meters. The air preheater is fed by 10°C cold air and the gasification air exits at 300°C. The heat transfer by air preheating is calculated to 3,9 MW, resulting in a cooling of the product gas to 700°C. Limestone is added in the gasifier, which operates at 800-850°C. At these temperatures, limestone will be calcined slowly (CaCO3 -> CaO + CO2) and CaO in the gasifier will act as the catalyst in the tar cracking process. By adding limestone, the gasification temperature can be increased compared with using only sand, since the alkali-silica compounds in sand are “sticky” in the temperature 750-950°C with risk of bed agglomeration. To keep the gasifier and the interior free from oxygen from the atmosphere, an inert gas (typically nitrogen) system must be established. In normal condition, inert gas is used as a blocking gas in places where leakage of oxygen may occur. Typical places are in the fuel feeding section, bed feeding and where the ashes are removed.


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In connection with stops, inert gas must be fed into the gasifier to prevent the reactive and poisonous product gas to leak out. This must also be done for the filter as long as it is hot to prevent oxygen to react with unburned carbon, which may cause severe damage to the filters.

11.4 Gas cooler system

The hot gas from the gas cooler will first be cooled in the air pre-heater to around 700°C. After that, the product gas is passed through a gas cooler section and heat exchanged with pressurized feed water. This heat released is high quality energy and can be used for preheating of main boiler feed water to increase the total efficiency. Temperature of the gas after the cooling is around 400°C. The heat released in this section is about 8 MW. Instead of drain some of the generated steam in the turbine to preheat the feed water; the heat generated in the gas cooler can serve as heat source for this purpose. The gas cooler is equipped with soot blowers (steam) to minimize problems of fouling on the heat exchangers material.

11.5 Gas cleaning system

The cooled product gas will be cleaned in barrier filters at a temperature somewhere around 400°C. At this temperature, it has been shown that it is possible to have heat exchangers surface temperatures above 350°C, which is considered to be minimum temperature for avoiding tar condensation and related fouling problems (van der Drift and Pels, 2004). Barrier filters include a range of porous materials that allows gases to pass through but prevent passage of particles. Particles of range between 0,5-100 µm in diameter can effectively be removed. Barrier filters can be designed to remove almost any size of particles, but the pressure difference across the filter will increase as the pore size decreases (Stevens, 2001). Pulsing gas is injected periodically through the filter in reverse direction of normal gas flow to clean the filter from captured particles. Three kinds of barrier filter can be distinguish:

• Rigid barrier filters • Bag filters • Packed-bed filters

Rigid barrier filters can be of ceramic or sintered metal barrier type and are sometimes called hot gas filters. These filters provide the opportunity to produce a clean fuel gas while retaining the sensible heat of the fuel gas. Ceramic filter can withstand temperatures around 900°C, while metal filters around 500°C (Jonsson, 2006). Ceramic and metal candle -type filters were both tested at the commercial demonstration plant in Värnamo, Sweden 1999. Metal filters have better mechanical


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strength than ceramic filters, thus longer lifetime and easier to handle (Jonsson, 2007). Later test at Värnamo were made with metallic candle filter elements because of severe breakage in the ceramic filters. Sintered metals are stronger and operate with lower pressure drops compared to ceramic filters. However, further development and improvement of ceramic filters may provide the low-cost option (Babu, 2003). Bag filters are made of woven material that intercepts small particles on the filter surface. The filters are periodically shaken or back-flushed to remove particulate accumulation. The textile filter can remove particles as effective as ceramic hot gas filters (Jonsson, 2007). Operation temperature is in the range of 400-450°C, which results in an effectively removal of alkalis by condensation. The pressure drop over a bag filter is generally quite low. Packed-bed filters may also act as barrier filter. These filters are based on a bed of granular material in which the product gas is passing through. The bed absorbs the particles and when the bed becomes full it needs to be cleaned, typically by back flushing. This concept has been in use at some small-scale gasifiers with sawdust or activated charcoal as bed material for removal of particles and tars. In larger systems, the problem with accumulation of particles or tars in the packed bed present potential operational problems. Therefore, this filter type has not being incorporated into larger-scale gasification systems (Stevens, 2001). Tests done by VTT has shown that ceramic bag filters works very well in temperatures around 400°C and can easily meet the limit values set by EU’s WID of heavy metals and dioxins. Bag filters are also cheaper than rigid barrier filters. Preheated, pressurized pulse gas is recommended to avoid cold spots in the filter with risks for tar condensation. The pulse gas in use might probably be nitrogen. The filter will capture dust and the condensed alkali and most of the heavy metals. By adding some sorbents, example Ca(OH)2, before the filter, most of the chlorine content can be captured in the filter (Palonen et al., 2006). To overcome the pressure drop over the filter and the cyclone, the gasifier is supposed to work with an overpressure. After cleaning, the gas is burned in low-calorific gas burners. The combustion air is taken from the main boiler air system. By placing the gas burners above the existing coal burners, an efficient re-burning effect may be achieved to reduce NOx emissions. However, problems with short residential time and high content of unburned carbon in the flue gas may be a problem using this approach. According to VTT studies some of the heavy metals may not be captured in the filter (e.g. Hg and Cd), which makes a bag filter unit, with sorbent feeding, necessary after the boiler. To avoid great damage in the cleaning section in case of explosion the section will be furnished with explosion doors.


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11.6 Fuel feeding system

The pressure in the reactor is slightly over atmospheric pressure, which makes the feeding of biomass into the gasifier to be pressurized. There is roughly three commercial principal to go; pressurize by infusion of gas to a closed vessel with fuel (Lock hopper system), pressurize the fuel by mechanical force against the pressure (plug-screw feeder) or pressurize the fuel by rotary feeders. In the lock hopper system, Figure 35, fuel is fed to a silo and after to the lock hopper. The two silos are equipped with valves at the top and the bottom. When the fuel is being pressurised, the valves are closed and gas is pressed into the silo. Bottom valve is opened and the pressurized fuel is fed to the pressurized silo meanwhile fuel is being fed into the other lock hopper. Residual gas from the first pressurization is fed into the other lock hopper and next cycle is started. To prevent fires and dust explosions in the feeding system, the oxygen concentration should be low and inert gas utilization is preferable (Liinanki and Karlsson, 1994). Disadvantages of this method are the large consumption of inert gas and the risk of operation failure due to the complex system.

Figure 35 Lock hopper system for fuel feeding to a pressurized gasifier (Liinanki and

Karlsson, 1994)23.

The principle of the plug-screw feeder is that the material is fed into the reactor by a conical transporter screw. The fuel is compressed due to the form of a screw and a hard plug is formed at the end, which act as a seal against the atmospheric surrounding. The technology is wide used and several pulp mills use it for feeding of chopped wood (Liinanki and Karlsson, 1994).

23 In the original figure the symbol text was in Swedish. This has been translated to English in figure 35.


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The third method for biomass feeding is rotary feeders. The system consists of a multivaned rotor within a pressure-containing housing. The pressure sealing is achieved by metal-to-metal contact between the vanes and the valve housing. The fuel is fed through an opening in the top of the housing and pressurized condition is accomplished by adding a fluid at or above the reactor pressure. Steam or air from the main gasification air fan may be used as sealing air. The advantages of the rotary feeder are that they can handle a variety of feedstocks and the construction is small sized relative to throughput. Disadvantages may be problems with wearing at the vanes, which makes continues exchanges necessary. One way to prevent unplanned stops may be to use two rotary feeders per line. The cost for a 20 dry-tons/hour rotary feeder is approximately $ 500 000 (Swanson et al., 2003). This technology is used at the gasification plant in Kymijärvi. The choice of feeding technology depends on which kind of fuel is being in use, the system pressure and what kind of pre-preparation it has been undertaken. The most interesting method for fuel feeding in this project seems to be rotary feeders, since only slightly overpressure is necessary. The technology is also very fuel flexible, which goes “hand in hand” with the CFB specifications.

11.7 Ash handling system

The ash from the gasification plant will come from:

• The bottom of the gasifier. • The bottom of the gas cooler. • The product gas filter.

The ash from the gas cooler bottom and ash from the product gas filter may contain so much unburned carbon and other hydrocarbon elements, so that they need further treatment before they can be taken away for deposit or utilized in the field again (ENERGI E2, 2001). Burning the ash in a small FB combustor may fix the problem. One other method may be to re-circulate part of the ash back to the gasifier and burn out the carbon content. This also include that most of the heavy- and alkali metals and chlorine content is fed back to the gasifier, which increase the concentration of impurities and may lead to operational problems such as fouling and bed agglomeration. To decide if this way is possible, analysis of the components in the filter ash must be done to decide the ash melting temperature. However, to increase the total efficiency of the plant, re-burning of the unburned carbon is necessary. The bottom ash from the gasifier has a low carbon content (Lahti 0,5 % carbon content), which makes combustion of the ash unnecessary. The mass ratio between bottom and filter ash is supposed to be 30/70 % (ENERGI E2). This makes filter ash


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processing of great importance, since large content of filter ash is expected. Especially when contaminated fuels with high ash content are used as feedstock. The pressure drop over the bed will decide the speed and operation of the bottom ash screw. If the pressure is above the set value, the screw starts to rotate. The bottom ash and the filter ash will be water-cooled and the heat released will be recycled in the process. To avoid product gas to go “backwards”, the ash cooling screws will be operating above the process pressure. Assuming a annual use of 160 000 tons biomass with a average ash content of 2 % and a bed material consumption of ca 500 kg/h, the total ash content will be around 6000 tons per year. 30 % (1800 tons) will be bottom ash while 70 % (4200 tons) will be in form of filter ash. Tests performed by VTT showed that the unburned carbon content in the filter ash after straw gasification was 26 %. By using eq. 13, the energy content in the filter ash can be calculated.

22 COOC →+ [q = 32,77 MJ/kg] (13) This means that the energy content in the filter ash is 8,5 MJ/kg, corresponding to 2,3 MW. This indicates the importance in filter ash re-burning to increase the plant efficiency. The biomass ash may be recycled, used as fertilizer, as building material, as fuel or be used as landfill. It depends on the ash composition and the political laws and rules.


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12 Economy of indirect co-firing systems The benefit of indirect co-firing is mainly not based on economics, rather the decrease in fossil fuels dependence and emissions to the atmosphere in forms of CO2. But for an increased fuel price and taxes for coal, stable prices for cheap biomass and subsidies for RE production, the concept can be considered to have economical potential. In 2001, ECN made a comparison between different co-firing technologies to investigate the possibilities for each concept. The concepts that were compared were direct co-firing substitute fuel in existing coal feeders, co-firing with separate size reduction, drying and feeding and indirect co-firing (gasification) with or without additional LT fuel gas cleanup. At this moment the gasifier in Geertruidenburg (Lurgi-technology) was in startup operation and based on wet scrubber technology as cleanup method. The other concept was based on Lahti-technology without any gas cleaning. The main boiler was a coal fired, 600 MWe, power plant with electricity efficiency of 40 % [LHV] and in operation 6000 h/year. For the coal fired CHP substitution of about 10 and 40 % of the energetic fossil fuel input was assumed, with the condition that the net overall electrical plant output remained constant. The results are shown in table 17.

Table 17 Results from the co-firing investigation made by ECN (van Ree et al., 2001)

As it can bee seen, direct co-firing is the cheapest option to reduce fossil CO2. However, direct co-firing is associated with higher fuel costs, a maximum fuel input (5-10 %), lowering the quality of the coal ash and may result in larger operational problems such as fouling and slagging. The two gasification technologies differ in cost and efficiency. This is due to the LT gas cleanup for the Lurgi-technology, where cost increases with more complex gas handling. The difference between the efficiency is because of the LT gas cleaning, which may end up in exergy losses when the product gas is cooled. However, this difference should not be this high at the moment since the gasifier in Geertruidenberg nowadays works with partial hot gas cleanup.


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12.1 Economics in general

Generally, energy systems based on indirect co-firing technology will always be more expensive than stand alone coal systems. Gasification co-firing applications will also be related to higher investment costs than for units based on direct gasification. According earlier mentioned positive effects for indirect co-firing, there may be a lowering operational cost, mainly based on cheaper fuels and less costs for emission taxes when more biomass via gasification is used. However, the capital cost may probably be much lower than establish new, biomass fired CHP, due to the fact, that the technology is based on already existing infrastructure and equipments (steam turbine, boiler etc.) at the coal power plant. Costs related to co-firing can be divided into some groups:

1. Capital costs (capital, interest costs, depreciation, etc.). Co-firing gasification unit’s costs in the range of 500-3000 EUR/kWe. Compared with other renewable energy options, this solution is very cost effectively to reduce CO2 emissions to the atmosphere.

2. Fuel related costs (fuel prices, pre-treatment, transportation, storage, etc.) One

of the most important factors in economics of co-firing is the cost of biomass fuel (Maciejewska et al., 2006). The cost of biomass fuels could be a subject to political decisions regarding environmental or preferential taxes, subsidies, or trade with emissions quotas. For example as in Sweden, where a tax of fossil carbon dioxide was introduced in the early nineties, which lead to a rapid increase of wood pellets as a fuel. Sweden also has a system based on green electrical certificates, which give the producer of electricity from renewable fuels, a green certificate for every produced MWhe. These certificates can later be sold on the market and the price has fluctuated around 20 EUR/certificate for the last five years.

3. Operational costs (maintenance, personnel costs, administration, insurance,

taxes, bed material, waste disposal costs).

12.2 Economical presumptions

The capital cost for a gasification plant is mostly depending on what kind of facility it is. However, the components of the plant are rather depending on the size. In general, the smaller the plant is, the higher the capital cost is per installed effect. The relation of capital cost and plant size is not linear, but rather follows eq. 14.

x

kk P

PII

⋅= (14)


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where: =I The investment cost for a specific plant/component of a plant with size P.

=kI The investment cost for the same plant/component of plant with size Pk.

=x Index that describes the relation between installed effect for a known plant with size Pk and the requested plant of size P.

The exponent, x, is varying for different components of the plant. It can be assumed that the components that have a size-dependence, the index is around 0,7 (Heat and power system, 2006). By the increasing demand for biomass fuels and the historical relation between biomass-, coal-, oil- and natural gas prices, the biomass prices will probably increase in a near future. This is already done for many bio-fuels, especially clean and pre-treated biomass. Other factors and presumptions that directly affect a bio-CHP plant economical presumptions and profitability are among others:

• Future inflation. • Future fuel prices. • Future electricity prices for “green power”. • Future tax changes and changes in trade with emissions quotas. • Future heat and power prices. • Changes and additions in environmental taxes, laws and political directions. • Economical subventions for green heat and power production. • New developed technology for CHP production, which makes the existing

plants unprofitable.

12.3 Operational and maintenance costs

Operation and maintenance costs are often represented as a fix and a varying cost. The annual fix cost for operation and maintenance can often be represented as a percental part of the total investigation cost for the plant. Some of the fix costs are:

• Insurance • Reparation and maintenance

The varying costs are for example:

• Consumption material • Chemicals and sorbents • Electricity, water • Cost for decay-product treatment. • Salaries.


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Plants that uses fuels like biomass and wastes, have higher operational and maintenance costs than for more “clean” fuels like natural gas. Especially fuels with high concentrations of ash and fuels that needs chemicals and sorbents in the flue gas cleaning section. In the report “El från nya anläggningar”, the cost for decay-product treatment is set to 1200 SEK/tonne for power plants (Hansson et al., 2007). Total operational cost is estimated from by using data from technical calculations and rules of thumbs obtained from literature.

Table 19 Operational costs for the gasification plant.

Operational cost

(without fuel costs)

Value MEUR

Energy consumption

(chipping, pumps, fans, etc.)

3 % of produced electricity from the gasifier

0,3

Decay product treatment 120 EUR/tonne24 0,75

Salaries 1 person/shift 0,3

Bed material costs

(sand + limestone)

500 kg/h, 45 EUR/tonne 0,15

Chemical and sorbents 0,1

Filter costs 0,4

Maintenance + insurance 3 % of TCI 2,0

Inert gas (N2) consumption 18 000 tons/year,

27 EUR/tonne25

0,05

Total operational costs 4,1

A total operational cost (without fuel costs) of 4,1 MEUR/year correspondence to a cost of 5,7 EUR/MWhfuel. This is quite low compared with biomass fired steam-based CHP. However, all the needed infrastructure, administration and personnel is already existing and turbine and boiler maintenance are already included in the operational costs for the coal boiler. This operational cost for the main boiler is assumed to be unaffected before and after modification.

12.4 Capital cost

The total capital investment cost (TCI) is based on cost of components related to a gasification plant, which were obtained from a literature survey. The specific costs of most system components are affected by their capacity. The general relation is based on eq. 14.

24 Hansson et al., 2007 25 ENERGI E2, 2001


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Figure 36 Index from Chemical Engineering Magazine (March 2007).

The figure above indicates that the plant cost index has increased rapidly recent years. Increasing demands and rising prices of construction materials are factors that have major influence on the CEPCI. As it can be seen, the CEPCI has increased with 20 % and the MSECI with 30 % only for the last four years. In the case where the cost information for components has been taken a couple a years ago, the index shown in Figure 36 has been used to recalculate to more updated values. After scaling, each component is calculated with relation to the plant size. In table 20 the cost for each component is shown.

Table 19 Total capital investment for the plant.

Component TCI MEUR

Biomass handling,

feeding and control system

8,426

Dryer 4,527

CFB gasifier

+ gas burners

17,128

Heat recovery boiler 7,0

Filter 1,029

Piping 2,0

Electrical works and system 5,0

Engineering 14,0

Contingencies 6,0

Total TCI for the plant 66,5

Cost per installed kWe 1390 EUR/kWe

26 Järvinen, 2002 27 Claes Münter, Exergy Engineering & Consulting 2008-05-14 28 Järvinen, 2002 29 ENERGY E2, 2001


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12.5 Profitability calculations

To calculate the plants profitability, a comparison has been done between today’s operation with 100 % coal and the case with some of the coal input substituted with gasified biomass. The two cases have been compared with respect to costs and incomes under an economical lifetime of 20 years. To compare the economical performance, the net present value is being used. The method is based on discounting all costs and incomes to one year. If the costs during year “j” is Cj, the revenues the same year is Rj and the total project period is z year, discounting to year zero with an interest rate i will give the net present value as:

∑ +−

=z

jjj

iCR

NPV0 )1(

(15)

The option with the highest NPV is the most attractive. By making a diagram, showing the accumulated NPV at year zero as a function of time, the time when the plant is repaid can be calculated. To calculate the internal rate of return (IRR), equation 15 is set to zero.

0)1(0

=+

−= ∑

z

jIRR

jj

iCR

NPV (16)

By doing so, the rate that generates a NPV equal to zero is calculated and indicates the efficiency of an investment.


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The plant’s economical performance is calculated with following conditions (Table 20):

Table 20 Base case conditions for the gasification plant.

Prices

Biomass (average) 12 EUR/MWh

Coal 8 EUR/MWh

Electricity price 40 EUR/MWhe

Heat price 30 EUR/MWh

Subsidies for electricity prod. from RE 35 EUR/MWhe

Taxes for heat prod. from coal 31 EUR/MWhe

Prices for CO2 quotas 25 EUR/tonne

120 MW th gasification plant 67 MEUR (TCI)

Interest rate (nominal) 8 %

Inflation 1,7 %

Economical lifetime 20 years

Operational costs for gasifier (not fuel) 4,1 MEUR/year

On the basis of the future penal tax of 25 EUR30 levied on every tonne of CO2 emitted in excess of the CO2 quotas, this amount is included as the value of CO2 saved when biomass is used. It should be noted that the heat price is a template value and has no effect on the comparison between the two cases. The analysis done for this case is under a 20 years operation period and the net incomes from co-firing biomass with coal is compared with the net incomes from firing 100 % (as today). The economical conditions and results are attached in appendix 5. The accumulated NPV is shown in Figure 37.

Accumulated net present value [MEUR]

-80,0

-60,0-40,0

-20,0

0,0

20,040,0

60,0

80,0

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Figure 37 Accumulated NPV of the gasification plant.

30 Hansson et al., 2007


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Investment in a biomass gasifier of 67 MEUR generates an NPV of 71 MEUR over 20 years. The accumulated NPV for each year can be seen from figure 41. The internal rate of return is calculated to 22 % and the pay-back time is about 5 years. In order to investigate the contribution from different parameters, a sensitivity analysis has been done for different cases (Table 21). Since the relative small changes in produced electricity and district heat production before and after modification, these prices only have small effects on the plants profitability.

Table 21 Parameters used in the sensitivity analysis.

Parameters Base case Range

TCI 67 MEUR 45-100 MEUR

Biomass price. 12 EUR/MWh 4-20 EUR/MWh

Coal price. 8 EUR/MWh 4-20 EUR/MWh

Subsidies for RE electricity production.

35 EUR/MWhe 0-40 EUR/MWhe

CO2 emission costs (from fossil fuels).

25 EUR/ton CO2 0-40 EUR/ton CO2

Taxes for heat production from coal.

30,7 EUR/MWh 0-40 EUR/MWh

By keeping all other parameters constant and varying the TCI, a analysis is made to see the importance in changes in the investment costs, Figure 38.

0

102030

4050

607080

90100

40 50 60 70 80 90 100

TCI [MEUR]

NP

V [

ME

UR

]

Figure 38 Sensitive analysis of the total plant cost.

Changes in fuel prices are shown in Figure 39.


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020406080

100120140160180200

4 6 8 10 12 14 16 18 20

Fuel cost [EUR/MWh]

NP

V [M

EU

R]

020406080100120140160180200

NP

V [

ME

UR

]

Coal price Bio price

Figure 39 Sensitivity analysis of the coal and biomass price31.

Changes in subsidies for electricity production, CO2 quotas costs and taxes for heat production are shown in Figure 40.

-200

2040

6080

100120

140

0 5 10 15 20 25 30 35 40 45

[EUR]

NP

V [

ME

UR

]

CO2 emissions costs [EUR/ton CO2]

Subsidies for biomass [EUR/MWhe]Taxes for heat production from coal [EUR/MWh]

Figure 40 Sensitivity analysis of subsidies for biomass and CO2 emissions quotas costs.

These analysis shows that the profitability for a gasification plant is very sensitive in changes to the base conditions. Even so, the NPV will be positive for all cases excepts for zero costs of CO2 emissions quotas costs. Without taxes on heat production from coal, costs for emissions quotas or subsidies for biomass utilization, this concept do

31 Observe. The fuel costs are dependent of each other, which make comparison between two new values impossible. Only fuel price for either coal or biomass can be changed according to the base case.


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not have any economical potential. However, all three is strongly dependent on the economical profits from a gasification plant. It is enough that only one of these parameters is taken away to make the plant unprofitable.


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13 Logistics and planning To retrofit an existing plant with a gasification unit, 4 potential prohibits can be distinguish. Technology knowledge and plant providers To build a gasification unit, knowledge and providers of the technology are needed. At the moment only a few indirect co-firing units has been built and the technology is quiet unproven. Practical possibility to built a gasification plant To retrofit a coal plant with a gasification unit requires enough of space for the gasifier and the fuel storage close to the plant. If the fuel will be pre-treated at the site, extra space must be considered for the fuel preparation unit, like fuel reception, crusher and dryer. To support a 120 MW gasifier with biomass with a heating value of 16 MJ/kg will need a fuel rate of ca 27 tons/hour. Assuming the received biomass contain 30 % moisture, this correspondence to a biomass input of 34 tons/hour. To guarantee two days support of fuel, a fuel storage of 1600 tons biomass is required. With a bulk density of 400 kg/m3 for biomass, this correspondence to a biomass volume of 4000 m3. This means that the storage will be enough until Monday at 14. With an average high of 2 meters, this is the size of a half football field. However, if the biomass is transported by ship, this storage has to be much greater. Logistics of biomass support To supply the power plant with biomass, some kind of transportation is necessary. Either by ship, train or with trucks. With a truck capacity of 70 m3 and a delivery of biomass between 07-18 on weekdays, 7-14 Saturdays, this will lead to almost 4 fully loaded trucks of biomass per hour. Infrastructure and traffic network will therefore be of greatest importance. Aspect from the opinion To retrofit an existing plant with a gasifier will probably lead to some aspects from the opinion. Close living citizens will maybe be disturbed because of noise from the traffic and from the plant. The landscape view will probably not be a problem since there already exist a plant. Positive response from the opinion may occur due to the reduction of GHG to the atmosphere.


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14 Evaluation and conclusions

14.1 General conclusions for indirect co-firing techniques

This report has investigated the possibilities of biomass gasification technologies and especially indirect co-firing techniques. Three interesting concept of biomass gasification can be distinguished. These are:

• Gas engine application. The produced gas is cooled and cleaned and thereafter burnt in a gas engine for CHP production.

• Gas turbine application. The produced gas is partly cooled and cleaned and burnt in a gas turbine integrated with a steam cycle (IGCC).

• Co-firing in a boiler. The produced gas is cooled/partly cooled and cleaned/un-cleaned and thereafter burnt in a boiler (Rankine cycle).

This report has mostly been focused on the last concept, co-firing biomass in existing boilers for heat and power production. The choice of this concept is the ability to substitute some of the coal input with gasified biomass to reduce CO2 emissions to the atmosphere. The technology is relative cost-effective and can be build in large-scale units. For this market purpose a CFB unit seems to be most interesting. The technology is quite proven at some pulp mills to substitute oil dependence and at a couple of power plants, mainly in Europe, has been build. The investigation has showed that these gasifiers can be operated without major problems. FW has delivered five operating units in the range of 25-70 MWth and Lurgi is operating one in Geertruidenberg and one at Rüdersdorf (see more section 6.2). However, most of the commercial co-firing gasifiers are working without any gas cleaning, which make the operation less complex. Studies and tests at pilot plants has shown that it is technical possible to scale -up gas cleaning systems, which make utilization of cheaper biomass possible. Increased focus on CO2 reduction and increased prices and taxes for fossil fuels in combination with subsidies for biomass has made biomass more profitable last years. The advantages with indirect co-firing compared with stand-alone biomass fired plants are the less investment costs and the increased electrical efficiency. Bigger plants often work with higher efficiencies. Techno-economical studies indicate that the main factors for profitability for indirect co-firing techniques are:

• Investment costs for a gasification plant. • Coal price. • Biomass price. • CO2 emissions and tax costs for coal. • Subsidies for RE production.


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Prices of heat and electricity are not of great importance, since almost the same amount of production is expected before and after retrofitting with a gasifier.

14.2 Conclusions of retrofitting Fynsvaerket with a gasifier

The main gasification concept in this report was to investigate the feasibility of replacing some of the coal input with gasified biomass in block 7 at Fynsvaerket, Denmark. The technology of focus has been on an air-blown atmospheric CFB with filter technology for gas cleaning connected to a PC fired plant. By substitute some of the coal with biomass, the net CO2 emissions can be reduced. The technology has not yet been commercial, but at least two plants can be distinguished as potential break-through. These are the 160 MWth plant in Lahti and the 200 MWth in Västerås. However, it is the gas cleaning section that has not been commercial, CFB gasifier has been in operation in several places for years at the moment. Gas streams at pilot plants and partial streams from operating CFB gasifiers has been tested for different filters under long term testing with satisfying results. It is possible to remove almost all of the alkali and heavy metal content (not Hg) and the chlorine content can be captured at 90-95 % level by adding sorbents before the filter and limestone in the gasifier. To maintain the plant electrical efficiency, the cooler section should be integrated with the main boiler feed water system. Calculation shows that the electrical output for co-firing ratios of 14 % is almost the same as before, assuming the fuel is dried and the cooling system integrated with the steam system. In the case of use waste fuels as feedstock, it is important that the plant is not classed as a waste incineration plant of WID. This is due to the high investment costs related to retrofit the plant with extensive flue gas cleaning and process controlling. Since the product gas is cleaned in the gasification facility, the measurements and processing must be in this system. By the increased concentration of impurities due to smaller volume flow, the processing can be facilitating. The economical profitability is strongly depending on the subsidies received for RE production and the taxes and costs for CO2 emissions related to coal utilization. The value of RE subsidies in this project calculation, are assumed to be 35 EUR/MWhe for the first 10 years and 8 EUR/MWhe for the next coming 10 years. However, this value is only valid if the plant is classed as a special RE plant of major importance. Therefore, further investigation has to be done to verify if this subsidy is valid for this case (see more Appendix 2). The dependence in heat and electricity prices is not very sensitive, since almost the same amount of electricity and heat is produced before and after the modification, but an increasing demand of district heating will make the concept more profitable, since no taxes is paid for heat production from biomass. By switching some of the heat load


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from block 3 to block 7 and operate block 3 in condensing mode, a more profitable situation may occur. The fact that block 8 (straw fired CHP) is under construction may lead to complication with local available biomass in form of straw. Prices may increase due to longer transportation and higher demands. The fact that block 7 was build in 1991 and has been in operation for 17 years, and that the economical lifetime of the gasifier is sat to 20 years, means that block 7 must be in operation for about 40 years for optimal economics. This is higher than a normal lifetime of a power plant. An other treat is that coal prices may rice to levels that make the plant unprofitable and shut down or decrease in annual operational hours. The economical calculations showed that with an economical lifetime of 20 years and with a nominal rate of 8 %, the net present value is 71 MEUR and the internal rate of return is 22 %. The cost per installed kWe of 1390 EUR is quite low in comparison with the values given in the report “El från nya anläggningar”, which indicate a cost of 28000 SEK/kWe for a 30 MWe and 21500 SEK/kWe for a 80 MWe stand-alone, biomass-fired CHP plant. A number of assumptions were made in the study in order to evaluate the plants economical performance. The assumptions where based on data obtained from the literature survey. Problems with this method are that different writers often have the same source, which leads to uncertainty. No commercial biomass gasification plant exists on the market today, a fact indicating that the technology is still under development. This indicates a high risk in investment of such a plant since no “know-how” experiences exists. However, both FW and Metso Power seem to be candidates as supplier to the two projects in Lahti and Västerås and both says that no technically problems will stop the project. Spaces for a gasification plant at Fynsvaerket should be no problems. The old coal harbor in the north side of the boiler is not longer in use. This seems to be a perfect area for a gasifier with a biomass fuel storage. The old harbor may also bee used to import biomass by boat to the plant.


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14.3 Further work

For continued work on the case of retrofit block 7 at Fynsvaerket, some further investigation has to be made.

• CFD simulations to see the effect of co-firing biomass in the boiler. • Filter ash processing. To investigate how the filter ash may be treated with

respect to unburned carbon, to increase the total efficiency. Can the ash be clean enough, low content of C and PAH?

• Further investigate the biomass fuel market in Denmark and the cost related to it. Is drying necessary? Probably not if straw is being used as feedstock. Is it more profitable to gasify pure waste even without subsidies?

• Investigate the rules according to gasify fuels that are classed as waste fuel. Is the plant classed as a waste incineration plant of WID or not?

• To receive the extra subsidies of 35 EUR/MWhe from biomass the plant has to fulfill the requirements of being a “RE plant of major importance”. The definition is not fully clear and the rules have to be further controlled.

• The effects on the SCR system has been reported to be negative in co-firing with biomass, which has to be further investigated. However, the problems with the system seems to be related to the alkali content in biomass and if the gas is cleaned it might not be any problems with the SCR.


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15 Acknowledgements This master thesis is done as a final part in the engineering program in Energy technology at the institution of applied physics and electronics, Umeå University. The work has been performed at the division of Research & Development at Vattenfall AB in Råcksta, Stockholm. I would like to thank all the personal at UVN and UVF for their support. I would like to send a special thanks to my supervisor Gerth Karlsson, for his help and support in this project. You did always have time for my questions and problems. Thanks. Thanks Hanna for listening and encourage me through this project. Stockholm, June 2008 Samuel Nilsson


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16 Abbreviations

AE Austrian Energy BFB Bubbling fluidizing bed BGGE Biomass gasification gas engine BMG Biomass gasification BTL Bio-fuel to liquid BTX Benzene, toluene, xylene CCS Carbon capture and storage Cd Cadmium CEPCI Chemical Engineering Plant Cost Index CFB Circulating fluidizing bed CFBG Circulating fluidizing bed gasification CH4 Methane CHP Combined heat and power CO Carbon monoxide CO2 Carbon dioxide DB Dry basis DKK Danish currency DME Di-methyl ether DS Dry substance ECN Energy research center Netherland ESP Electrostatic precipitator EF Entrained flow EU European union EUR European union currency FB Fluidized bed FERCO Future Energy Resources FG Flue gases FTD Fischer-Tropsch diesel FW Foster Wheeler GE General Electric GHG Green house gases H2 Hydrogen H2O Water/steam HCl Hydrogen chloride Hg Mercury HHV Higher heating value IGCC Integrated gasification combine cycle IRR Internal rate of return K Potassium


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kWfuel Kilowatt fuel kWh Kilowatt hour kWhe Kilowatt hour electricity LE Lahti Energia LHV Lower heating value LT Low-temperature MJ Mega joule MSECI Marshall & Swift Equipment Cost Index MSW Municipal solid waste MWfuel Megawatt fuel MWth Megawatt thermal MWh Megawatt hour MWhe Megawatt hour electricity MWe Megawatt electricity N2 Nitrogen Na Sodium Nm3 Normal cubic meter NPV Net present value NOx Nitrogen oxides O2 Oxygen PAH Polyaromatic hydrocarbons PWP Paper, wood, plastics Pb Lead PC Pulverized coal R&D Research & Development RDF Refuse derived fuels RE Renewable energy REF Recycled energy fuels SCR Selective catalytic reduction SNCR Selective non-catalytic reduction SNG Synthetic natural gas SWOT Strengths, weaknesses, opportunities, threats Syngas Synthetic gas TCI Total plant cost VEGA Vedförgasning VOC Volatile organic compound TPS Termiska processer VTT Technical research center of Finland WB Wet basis WID Waste incineration directive Zn Zinc


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17 References Alakangas, E., Heikkinen , A., Lensu, T., Vesterinen, P., 2007, ”Biomass fuel trade in Europe: Summary Report VTT-R-03508-07, VTT, EUBIONET II, March 2007. Babu, S, P., 2006, “Perspectives on biomass gasif ication”, Thermal gasification of biomass, task 33, IEA Bioenergy Agreement, Work Shop No. 1, May 2006. Babu, S, P., 2005, “Observation on the current status of biomass gasification”, Thermal gasification of biomass, task 33, March 17, 2005. Babu, S, P., 2003, “Summary of operational experience with recent biomass gasification demonstration plants”, Task 33, IEA Bioenergy. Belgiorno, V., De Feo, G., Della Rocca, C., Napoli, R.M.A., 2002, “Energy from gasification of solid wastes”, Department of Civil Engineering, University of Salerno, Fisciano (SA), Italy. Berg, M., Andersson, C., Ekvall, A., Eskilsson, D., de Geyter, S., Helgesson, A., Myringer, Å., Wikman, K., Öhman, M., 2005, ”Förbränning av utsorterade avfallsfraktioner”, ”Combustion of refused derived fuels”, Värmeforsk, Miljö- och förbränningsteknik, ISSN 0282-3772, in Swedish. Bridgwater, A.V., Toft, A.J., Brammer, J.G., 2002, “A techno-economic comparison of power production by biomass fast pyrolysis with gasification and combustion”, Renewable & sustainable energy reviews, page numbers 181-284. Cengel, Y., Turner, R H., 2005, “Fundamentals of thermal-fluid sciences”, Second edition, ISBN 0-07-245426-1. DEFRA., 2006, ”Guidance on Directive 2000/76/EC on the incineration of waste”, edition 3, Department of Environment, Food and Rural Affairs, product code: PB11941. Demirbas, A., 2002, “Sustainable cofiring of biomass with coal”, Department of chemical education, Caradeniz Technical University, Trabzon, Turkey. Duman, M., Boels, L., 2007, “The waste incineration directive and its implementation in the Netherlands: Assessment of Essent’s waste wood gasification process, University of Groeningen.


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ENERGI E2., 2001, “Straw gasification for co-combustion in large CHP-plants”, Project partners: Foster Wheeler Energia Oy and ENERGI E2 A/S, project nr: 1999/C77/13 and 1999/C77/15. FFP., 2007, “Material from the course in Combustion, gasification and pyrolysis, 5p at Umeå University autumn 2007”. FramTidsbränslen, 2005, “Sundsvall Demonstration Plant - Förstudie för production av Fischer Tropsch diesel”, Pre-study done by FramTidsbrönslen AB for FOKUSERA Utveckling Sundsvall AB. In swedish. Fynsvaerket., 2007, “Grönt regnskap 2006”, Environmental report of Fynsvaerket. In danish. Granatstein, D.L., 2002, “Case study on Lahden Lampovoima gasification project Kymijarvi power station, Lahti, Finland”, IEA Bioenergy Agreement Task 36. Hannula, I., Lappi, K., Simell, P., Kurkela, E., Luoma, P., Haavisto, I., ”High efficiency biomass to power operation experience and economical aspects of the novel gasification process”, Bioenergy 2007-Book of Proceedings, 15th European Biomass Conference & Exhibition, 7-11 May 2007, Berlin, Germany. Hansson, H., Larsson, S-E., Nyström, O., Olsson, F., Ridell, B., 2007, “El från nya anläggningar-Jämförelse mellan olika tekniker för elgenerering med avseende på kostnader och utvecklingstendenser”, Elforsk, report nr. 07:50. In swedish. Heat and power system., 2006, “Material from the course in Heat and power system, 5p at Umeå University autumn 2006”. Held, J., Karlsson, S., 2008, “Nyhetsbrev nr 1 2008- Förgasning och metanisering”, Svenskt Gastekniskt Center AB, in Swedish. Hofbauer, H., 2007 “Conversion technologies: Gasification overview”, 15th European Biomass Conference & Exhibition, 7-11 May 2007, Berlin, Germany. Jonsson, M., 2006, “State of the art of biomass gasification”, Vattenfall, 2006/12, Report no. U 06:137. Jouret, N., Helsen, L., Van den Bulck, E., 2005, “Study of the woodgasifier of the power station of Ruien”, K.U.Leuven, Department Mechanical Engineering, Division Applied Mechanics and Energy Conversion, Heverlee (Leuven), Belgium.


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Järvinen, T., 2002, “The analysis report of plant NO. 19”, Cofiring of biomass - Evaluation of fuel procurement and handling in selected existing plants and exchange of information (COFIRING) - Part 2, VTT Energy. Karlsson, G., 2008 “Interview with supervisor Gerth Karlsson during spring 2008”. Kavalov, B., Peteves, S.D., 2005, “Status and perspectives of biomass-to-liquid fuels in the European Union”, European Commission Directorate-General Joint Research Centre, Petten, the Netherlands, EUR 21745 EN, ISBN 92-894-9784-X. Kays, W.M., Crawford, M.E., Weigand, B., 2004, “Convective heat and mass transfer”, fourth edition, ISBN 0-07-246876-9. Kavalov, B., Peteves, S.D., 2004 ”Bioheat applications in the European Union: An analysis and perspective for 2010”, European Commission Directorate-General Joint Research Centre, Petten, the Netherlands, EUR 21401 EN, ISBN 92-894-8730-5. Kivelä, M., 2007, “Power point from Lahti Energia Oy”. Krzysztof, J Ptasinski., M, J, Prins., Anke Pierik., 2005, “Exergetic evaluation of biomass gasification”, Energy (2005), doi:10.1016/j.energy.2006.06.024. Kurkela, E., 2008, “Biomass gasification technologies for advanced power systems and synfuels- Status and present R&D activities at VTT”, Power-point from National flame days in Tampere, 23/1 2008. Kurkela, E., 2002, “Review of Finnish biomass gasification technologies”, OPET report 4, VTT. Lahtistreams., 2007, “Advanced integrated waste management and WtE demonstration”, Powerpoint from workshop in Helsinki 18-20.6.2007. Liinanki, L. Karlsson, G., 1994, ”VEGA Test & verifikation – Trycksatt förgasning av biobränslen”, Vattenfall, 1994/12, Project no. 38590. In Swedish. Lystbaek, E., 2008, “Interview with Einer Lystbaek, senior engineer at Fynsvaerket, 2008-05-23”. Maciejewska, A., Veringa, H., Sanders, J., Peteves, S.A., 2006, ”Cofiring biomass with coal: Constraints and role of biomass pre-treatment”, European Commission Directorate-General Joint Research Centre, Petten, the Netherlands, EUR 22461 EN, ISBN 92-79-02989-4.


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Maniatis, K., 2001, “Progress in Biomass Gasification: An Overview”, Directorate General for Energy & Transport, European Commission, Brussels, Belgium. Meijer, R., 2003, “Fuel gas cofiring”, IEA Bioenergy Agreement, Task 33: Thermal Gasification of biomass, Arnhem, the Netherlands. Münter, C., 2008, “Mail contact with Claes Munter, Exergy Engineering & Consulting 2008-05-14”. NETBIOCOF., 2006, “New and advanced concepts in renewable energy technology Biomass”, Project title: Integrated European Network for Biomass Cofiring. Project NO: SES6-CT-020007-(SES6). Nielsen, K., Ehrstedt, T., 2000, “Reningsteknik för organiska ämnen i utsläpp till luft vid biobränsletorkning”, “Abatement technologies for Volatile organic compounds in emissions from bio-fuel driers”, Värmeforsk, ISSN 0282-3772. Nieminen, M., Karki, J., 2007, ”Status of co-firing technologies within Europa”, IEA environmental projects limited (UK), AEBIOM, contract NO 19668. Nikolaisen, L., 2006, “Current situation and future trends in biomass fuel trade in Europe”, EUBIONET II, DTI. Nordin, A., 2008 ”Interview with Anders Nordin 2008-01-29”. Olofsson, I., 2005, ”Low-tar-Formation using High-Temperature Flash-Gasification of Intelligent Biomass Fuel Mixtures”, 2005. Olofsson, I., Nordin, A., Söderlind, U., 2005, “Initial review and evaluation of process technologies and systems suitable for cost-efficient medium-scale gasification for biomass to liquid fuels”, ETPC Report 05-02, Energy Technology & Thermal Process Chemistry, University of Umeå, Department of Engineering, Physics and Mathematics, Mid Sweden University, Sundsvall, Sweden, ISSN 1653-0551. Padban, N., Nilsson, T,. Berge, N., 2002, ”Energi ur avfall genom förgasning“, TPS, 2002/10, report no. TPS-02/16. In Swedish. Palonen, J., Anttikoski, T., Eriksson, T., 2006, ”The Foster Wheeler gasification technologies for bio-fuels: Refuse-derived fuel (RDF) power generation”, Foster Wheeler Energia Oy.


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Rauch, R., “Indirectly heated gasifiers – The case of the Güssing reactor”, Institute of Chemical Engineering, Vienna, Austria. Rensfelt, E., 2005, -Power point slide, ERen Energy. Rutherford, J.P., Williamson, C.J., “Heat and power applications of advanced biomass gasifiers in the New Zealand wood industry”, Department of Chemical and Process Engineering, University of Canterbury, New Zealand. Salo, K., 2005, “Gasification/ Gas Engine Project in Skive , Denmark”, Carbona Inc., Finland, article in Gasnet. Scott, T., 2007, “The largest gasification plant in the world”, article in FIB Bioenergy Research, fourth volume, June 2007. Stevens, D, J., 2001, “Hot gas conditioning: Recent progress with larger-scale biomass gasification systems”, NREL, report no: NREL/SR-510-29952. Strömberg, B., 2005, “Bränslehandboken”, ”Handbook of fuels”, Värmeforsk, Miljö- och förbränningsteknik, ISSN 0282-3772. Swanson, M, L., Musich, M, A., Schmidt, D, D., Schultz, J, K., 2003, „Feed system innovation for gasification of locally economical alternative fuels (FIGLEAF), Energy & Environmental Research Center, University of North Dakota. Van der Drift, A., Pels J.R., 2004 ”Product gas cooling and ash removal in biomass gasif ication”, ECN, the Netherlands, ECN-C—04-077. Van der Drift, A., Boerrigter, H., Coda, B., Cieplik, M.K., Hemmes, K., 2004, ”Entrained flow gasification of biomass – Ash behavior, feeding issues, and system analyses”, ECN, the Netherlands, ECN-C—04-039. Van Dijen, F., 2006 “Biomass Co-processing and Co-firing”, ThermalNet workshop, April 5, 2006, Lille, France. Van Ree, R., Korbee, R., Meijer, R., Konings, T., van Aart, F., 2001, “Operational experience of (in)direct co-combustion in coal and gas fired power plants in Europe, ECN, ECN-RX—01-008. Veijonen, K., Vainikka, P., Järvinen, T., Alakangas, E., 2003, ”Biomass cofiring – An efficient way to reduce greenhouse gas emissions”, EUBIONET.


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Waldheim, L. Blackadder, H, W., 1990, ”Förgasning av träbränsle och elproduktion med dieselmotor”, Studsvik Energy, 1990/12. In swedish. Wester, L., 2002, “Förbrännings- och rökgasreningsteknik”-“Combustion and flue gas cleaning technology”, Material from the course in Heat and power system, 5p at Umeå University autumn 2006. In swedish. Wilén, C., Salokoski, P., Kurkela, E., Sipilä, K., ”Finnish expert report on best available techniques in energy production from solid recovered fuels”, Finnish environment institute, ISSN 1238-7312. BIO-CHP, 2008, http://bio-chp.dk-teknik.dk/plants/güssing.mht Access date 2008-03-19 Danish Energy Agency, 2008, http://www.energistyrelsen.dk/sw23761.asp Access date 2008-04-29 Energimyndigheten, 2008, http://www.energimyndigheten.se/ Access date 2008-02-24 Energistyrelsen, 2008, http://www.energistyrelsen.dk/sw17278.asp Access date 2008-05-20 ECN, 2008, http://www.ecn.nl/en/bkm/products-services/olga Acess date 2008-03-05 Nordpool, 2008, http://www.nordpool.com Acess date 2008-04-15 Renet, 2008, http://www.renet.at Access date 2008-03-14


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Appendix 1 Plant visit at the Kymijärvi power plant

Hemmo Takala was guiding me at the Kymijärvi power plant, owned by Lahti Energia Oy, the 28 of April 2008. Hemmo described the power plant in general and the gasification plant in particular and answered some of the questions I had. He described the fuel way from receiving station, to fuel preparation and transportation to the gasifier and finally, the processing of the product gas into the main boiler.

Figure 1 The power plant in Kymijärvi.

The CHP plant in Kymijärvi is own by the Finnish company Lahti Energia Oy and is supplying the citizens of Lahti with heat and electricity. The boiler was built 1976 and was originally fired with heavy fuel oil. Because of the high oil prices early in the 80`s, it was converted to burn coal. In 1986, a natural gas turbine combined cycle was connected. Maximum electricity production is 185 MWe and district heating is 250 MWth. Steam data is 125 kg/s and 170/40 bar at 540/540°C. The coal boiler is a once-through Benson-type unit. 1998, a gasifier was connected to the power plant, providing low-calorific gas to two gas burners, located below the existing coal burners. Thermal effect of the gasifier is between 40-70 MWth, depending on composition and the moisture content of the fuel.


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Fuels for gasification in Kymijärvi is mostly REF (Recycled Energy Fuels, from industries and households), waste wood (grinding dust, demolition wood, plywood) and clean wood, such as bark, wood chips and forest residues. Fuel contracts are signed on one or two years basis excepts for REF since the use of these fuels in the gasifier has no guaranteed future. The interpretation of WID is not yet clear. Is the combustion of gasifier gas incineration of wastes or not? Emission limits are much lower for waste plants than for clean fuel fired plants. Today the plant operates without any SO2 or NOx removal system excepts for staged burning and flue gas recirculation. However, without these systems the plant cant meet these restrictions. Lahti Energia Oy has therefore investigate the feasibility to built a new gasification plant consisting of two gasifier lines, each 80 MW with gas cleanup, to meet the WID restrictions. Therefore, a gas cleaning plant was operating in Lahti for 3000 hours, where a part of the product gas was separated, cooled and cleaned from dust and heavy metals. This project was done in cooperation with FW and VTT to investigate the utilization of this technique. More about this in section 6.1.1. Plant calculation costs for such a plant was estimated to 100 MEUR three years ago but is nowadays reported to be doubled to 200 MEUR. This is the case for FW as supplier. A discussion with Metso Power is also taken in place. It should be noted that this sum also includes construction of a steam boiler unit and a new steam turbine. However, at the moment, the question of REFs future for direct combustion is under process at the Highest Administrative Court of Finland, and decision will be taken under the autumn 2008. Waste incineration is a controversial question in Finland and it is a long process to get environmental permits to built a plant. For the moment, REF stands for 40 % of the energy input to the gasifier. The price for REF is almost zero on an annual basis, since sometimes LE gets paid for taking the fuel. Biomass prices varying between 3-12 EUR/MWh. For March 2008 the average price of feedstock was 4,33 EUR/MWh, which must considering being very cheap. The specification for the fuel that has to be fulfilled are as following:

Table 1 Fuel specifications that have to be fulfilled.

Content Average % (of massdry) Maximum % (of massdry)

Cl 0,15 0,30

Cu 0,001

Na 0,06 0,12

K 0,05 0,10

Al 0,30 0,40

On an average basis, the fuels contain 25-30 % moisture, 19-20 MJ/kgDB and with an ash content of 5 %.


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REF and pre-treated bio-fuels are received in two separate receptions. The REF and untreated biomass is thereafter pushed via a bucket loader to the primary shredder, while the pre-treated biomass is mixed with the REF and the untreated bio-fuel and transported to the screening station. Here the fuel mix is passed through a magnet separator and finally crushed to a size of maximum 50 mm. This is where the most common problems occur. Problems with the final shredder seem to be a major problem and were standing the day I did my plant visit. One other problematic situation is the under-dimensioned receiving station for the pre-treated biomass, where unloading of a track takes up to an hour to fulfil. However, after the screening station, a chain conveyor transports the fuels to the intermediate storage, which has a capacity of 3000 m3. This is enough for 1,5 days of full load operations of the gasifier. From here, the fuels are transported by a chain conveyor to the two bins located at the top of the gasifier, containing 10 m3 each with down opening inclination angles. Two screws are located under the bin to discharge the fuel. The fuel is fed above the air distribution grid trough two block-feeders per line. Receiving of fuels are weekdays between 7-22 and on Saturdays between 7-16. One person per shift is working with the biomass treatment, while operating the gasifier is done with same operators as for the steam boiler. The gasifier is an air-blown atmospheric CFB with a cyclone and returning leg. Bed material in use is sand and limestone and the consumption is approximately 200-300 kg/h. The produced gas is fed to the two large gas burners located at the bottom of the sidewall of the steam boiler. The energy content of the gas is approx. 10 % of natural gas, which makes the large burners necessary. In normal operations, the fuel feed rate defines the capacity and the air feed rate controls the temperature. In start-up operations, one 5 MW natural gas-fired burner is operating to a reactor temperature of 600°C. Thereafter biomass and REF can be used in gasification mode. Approximately, 10-20 starts and stops of the gasifier yearly compared with 0-5 starts and stops for the steam boiler. This means that the availability is probably lower for the gasifier than the main boiler. However, the main boiler can work with 100 % effect even without the gasifier. Problems with the gasification plants seems to be associate with the fuel handling and preparation system and not the gasifier it self. Operational time for the gasifier and steam boiler is shown in table 2.

Table 2 Operational time for the main boiler and the gasifier (2004-2007).

Year Steam boiler (h) Gasifier (h) Availability of gasifier (%)

2004 7873 6944 88

2005 5991 5196 87

2006 8021 7336 91

2007 7380 5892 80


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2007 was a problematic year for the gasifier, since large problems in the fuel preparation section occurred several times. Problems with bed agglomeration has only occur 3 times in the beginning of the gasifier start-up period in the late of 1998 because of using a fuel with high amounts of potassium and sodium. No problems with unburned carbon have been reported. Corrosion probes in the main boiler has showed no abnormal deposit formation or high-temperature corrosion. The same steam data is used as before the modification. Bottom ash from the gasifier is removed by a water-cooled screw to a 10-m3 container, which needs to be emptied every day. The ash from the REF makes the gasifier ash not useful for further purpose and is therefore used for deposit. The fuel contains 5 % ash on an annual basis and bottom ash stands for 2000-3000 tons/year. The own electricity consumption for the gasifier is reported by Hemmo to be less than one MWe and the total gasifier efficiency is close to 100 % (Takala). Total investment of the gasification project was 12 MEUR, where 3 MEUR was financed by the EU THERMIE programme.

Figure 2 Fuel handling lay out.


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Figure 3 Fuel handling cross-section.

Figure 4 Picture taken from the chain conveyor to the gasifier (Samuel Nilsson).

1 Coal yard 4 Bio-fuel reception

2 Screening station 5 Intermediate storage

3 REF reception 6 Chain conveyor (to gasifier)


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Figure 5 Picture of the biomass fuel storage (Samuel Nilsson).

Figure 6 Picture of the REF reception (Samuel Nilsson).


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Figure 7 Process picture of the gasifier.


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Appendix 2 Subsidies for electricity generating plants in Denmark.

Existing decentral CHP plants using natural gas or waste (Danish Energy Agency, 2008):

• Plants with output over 5 MW Plant owners are responsible for sale of production on the electricity market and for related costs. Individual subsidy given based on previous subsidy in the period 2001-2003, paid monthly and adjusted in relation to the mean monthly spot price. The subsidy will be index-linked annually during 2005-2009. It is payable for a period of 20 years from the date of grid connection and for at least 15 years as from 1 January 2004.

• Plants with output of or less than 10 MW The transmission system operator will sell the production on the spot market. The subsidy together with the market price will ensure a tariff called 'three-tier tariff'. The tariff is index-regulated every quarter and was at the start of 2005 approx. 0,22 DKK/kWhe at low demand, approx. 0,46 DKK/kWhe at high demand and approx. 0,59 DKK/kWhe at peak demand. Consequently, a typical mean annual tariff of 0,30-0,40 DKK/kWhe is achieved.

General for plants using a combination of other fuel and renewable energy (RE) For combined fossil/RE plants, the element of production from RE sources is eligible for a special premium up to 0,26 DKK /kWhe, as described below. Subsidies for electricity producing plants using renewable energy in Denmark (Danish Energy Agency, 2008):

• RE plants connected to the grid before 21 April 2004

The transmission system operator will sell the production on the spot market. The subsidy together with the market price will ensure a tariff of 0,60 DKK/kWhe for 20 years from the date of grid connection and for at least 15 years as from 1 January 2004.

• Biogas plants connected to the grid between 22 April 2004 – 31 December

2008


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The transmission system operator will sell the production on the spot market. The subsidy together with the market price will ensure a tariff of 0,60 DKK/kWhe for 10 years and 0,40 DKK/kWhe for the following 10 years. The subsidy implies that the total use of biogas not exceed 8 PJ/year.

• Special RE plants of major importance and connected to the grid after 21

April 2004 Special plants using energy sources or technologies of major importance to future exploitation of RE electricity include wave power, solar energy, fuel cells using renewable energy sources, biomass gasifiers and Stirling motors or the like with biomass. Other types of plant can be approved apart from water turbines in rivers and production technologies already in use for biomass incineration. The transmission system operator will sell the production on the spot market. The subsidy together with the market price will ensure a tariff of 0,60 DKK/kWhe for 10 years and 0,40 DKK/kWhe for the following 10 years.

• Other RE plants connected to the grid after 21 April 2004

The transmission system operator will sell the production on the spot market, and the owner receives the market price and for 20 years a premium of 0,10 DKK/kWhe.

Subsidies for electricity producing plants using renewable energy in combination with other fuels (Danish Energy Agency, 2008): These executive orders apply if annual RE utilisation is between 10% and 94% of the combustible value of the total fuels. Plant owners are responsible for sale of RE production on the electricity market and related costs, providing the same applies to the other production.

• Plants in which use of RE began before 21 April 2004 RE-based production is eligible for a premium of 0,26 DKK/kWhe for 20 years and for at least 15 years as from 1 January 2004.

• Plants using biogas connected to the grid 22 April 2004 – 31 December 2008

Biogas-based production is eligible for a premium of 0,26 DKK/kWhe for the first 10 years and 0,06 DKK/kWhe for the following 10 years. The subsidy implies that the total use of biogas not exceed 8 PJ/year.

• Special RE plants of major importance where RE use commenced after 21

April 2004


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Special plants using energy sources or technologies of major importance to future exploitation of RE electricity include wave power, solar energy, fuel cells using renewable energy sources, biomass gasifiers and Stirling motors or the like with biomass. Other types of plant can be approved apart from water turbines in rivers and production technologies already in use for biomass incineration. RE-based production is eligible for a premium of 0,26 DKK/kWhe for the first 10 years and 0,06 DKK/kWhe for the following 10 years.


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Appendix 3 Layout and pictures of Fynsvaerket

Figure 1 Layout of Fynsvaerket.


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Figure 2 Pictures of Fynsvaerket (south side, north side, north side & north side).


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Appendix 4 Process conditions for block 7


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Appendix 5 Profitability calculations

Documents

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