Des Ulp H Urization in Peat-Fired Circulating and Bubbling Fluidized

h * -' . 1 TUTKIMUSRAPORTTEJA FORSKNINGSRAPPOR TER RESEARCH REPORTS

Des ulph urization in peat-fired circulating and bubbling fluidized bed boilers

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6* Petri Kouvo @/ Keijo Salmenoja e*@ &@Y@ 4 DISCLAIMER

Portions of this document may be illegible electronic image products. Images are produced from the best available original document. DES U LPH URlZATl 0 N I N PEAT- FI RE D CIRCULATING AND BUBBLING FLUIDIZED BED BOILERS

PETRI KOUVO IMATRAN VOIMA OY IVO TECHNOLOGY CENTRE

KEIJO SALMENOJA KVAERNER PULPING OY Published by Code IMATRAN VOIMA IVO-A-06/97 OY Date

Name of project DesulDhurization in Deat-fried circulating and bubbling fluidized bed boilers Authors Commissioned by Petri Kouvo IMATRAN vowOY Keijo Salmenoja

I Title DESULPHURIZATION IN PEAT-FIRED CIRCULATING AND BUBBLING FLUIDIZED BED BOILERS

Abstract The new emission limit values for large combustion plants are under consideration both at the EU level and in Finland. Peat and wood are the only indigenous fuels of Finland. In 1995 appr. 8 8 of electricity was produced with peat. The lower heating value of peat is around 10 hWkg. The moisture content varies between 35-55 % and sulphur content in dry solids between 0.15-0.35 %. The total peat power capacity of Finland in 1995 was 1400 MW. Because there was not enough information available about the desulphurization of the flue gases from peat-fired fluidized bed boilers, a group of Finnish companies and Ministry of Trade and Industry decided to carry out the full-scale desulphurization study. In project the desulphurization with limestone injection into the furnace of two types of peat-fired boilers were studied. The goal of the project was to investigate -what the technically and economically feasible emission level is reachable by limestone injection in the fluidized bed combustion -how the limestone injection affects the other flue gas emissions and the fouling of the boiler and, -what the economy of desulphurization is.

The tests were carried out at Kokkola and Kemi power plants in Finland. At Kokkola (108 MWf)circulating fluidized bed boiler, the emission limit of 200 mg/m3n was reached at a CdS-molar ratio of appr. 10, with limestone containing 92 8 of calcium carbonate, CaC03. At Kemi (267 MWf) bubbling fluidized bed boiler, the emission limit of 280 mg/m3n with limestone containing appr. 95 8 of CaCO3 was reached at a CdS-molar ratio of appr. 7.0. Emissions of NOx, N20, NH3 and dust after the ESP were not elevated due to the limestone feed. At the Kokkola power plant the NOx emissions varied from 300 to 400 mg/m3n, and, at the Kemi power station the NOx emissions were around 200 mg/m3n. The fouling of the Kemi boiler was found to be significant in the scheduled outage after the test period. The Kemi boiler was fii with waste sludges and bark between the test runs. This has most likely caused the fouling in the boiler. At the Kokkola power plant, the indications of fouling were not observed during or after the test. In both Kokkola and Kemi cases, the runs with the emission levels of 200 and 280 mg/m3n respectively about doubled the amount of the produced fly ash. The handling of the fly ash was aggravated because of the high free calcium oxide content. In the case of Kokkola power plant the desulphurization costs at the emission level of 360 mg/m3n (140 mgMJ, current emission level), are 7 900 FIW removed SOz tonne. At the emission level of 200 mg/m3n (appr. 77 mg/UT) the cost is 10 800 FIWremoved SOz tonne. The marginal cost of the desulphurization (360->200 mg/m3n) in Kokkola case is 12 600 FIWremoved SO2 tonne. In the case of Kemi power plant at the emission level of 360 mg/m3n, the cost is 8 400 FIWremoved SO2 tonne and at the emission level of 280 mg/m3n (the reached emission level), the cost is 11 600 LlhWremoved SO2 tonne. The marginal cost (360->280 mg/m3n) is 16 100 FIWremoved SO2 tonne. A calculation was also made for the Semi-Dry desulphurization method for both boiler type at the emission level of 200 mg/m3n. The costs for the Kokkola plant is 40 300 FIWremoved SOz tonne and for the Kemi power plant 19 OOO FIWremoved SOz tonne. The limestone price used in the calculations was 270 FIhWtonne at the site.

ISBN Language [SBN 951-591-054-4 English Number of pages Confidentiality 25 Public Distributed by price- MATRAN VOIMA OY NO Technology Centre Tel. +358 9 856 11 01019 Ivo Telefax +358 9 563 2225 FINLAND FOREWORD

Desulphurization in Peat-fired Circulating and Bubbling nuidized Bed Boilers project has been executed by Imatran Voima Oy (NO), a Finnish power company and Kvaerner Pulping Oy.

Mr Ilari Ekman MSc (Eng) of NO has acted as the director of the project. Mr Petri Kouvo MSc (Eng) of IVO and Mr Keijo Salmenoja of Kvaerner Pulping Oy have acted as the project engineers. The members of the Management Group have been: Ms Sirpa Salo-Ashinen, Minis- try of the Environment; Mr Seppo Oikarinen, Ministry of Trade and Industry; Mr Birger Ylisaukko-oja, Pohjolan Voima Oy; Mr Matti Hiltunen, Foster wheeler Ener- gia Oy; Mr Juha Sarkki, Foster Wheeler Energia Oy; Mr Markku Miettinen, VAPO Oy; Ms Maija Vihma, Partek Nordkallr Oy Ab; Mr Seppo Partonen, NO. The Chair- person of the Management Group has been Ms Leena Nurmento of NO’SEnviron- mental Protection Division.

The project has been financed by: Ministry of Trade and Industry, Foster Wheeler En- ergia Oy, Kvaerner Pulping Oy, VAPO Oy, Partek Nordkalk Oy Ab, Pohjolan Voima Oy and Imatran Voima Oy.

June, 1997

Imatran Voima Oy DESULPHURIZATION IN PEAT-F'IRED CIRCULATING AND BUBBLING FLUIDIZED BED BOILERS

ABSTRACT

FOREWORDS 1. BACKGROUND...... 5 2 . OBJECTIVES ...... 6 3 . THEORY OF DESULPHURIZATION ...... 6 4 .FLUIDIZED BED COMBUSTION...... 7 4.1 DESULPHURIZATIONINFLUIDIZED BED BOILERS ...... 9 5. KOKKOLA POWER PLANT ...... 10 5.1 THFi TEST PROGRAM FOR KOKKOLAPOWER F'LANT ...... 11 5.2 MEASUREMENTS.SAMPLES AND ANALYSES ...... 12 5.3 PEAT QUALITY AND PROCESS VALUES ...... 13 5.4 TEST RESULTS ...... 14 5.4.I CalS-ratio and the desuEphurizution rate ...... 14 5.4.2 Desulphurization and the bed temperature ...... 16 5.4.3 Desulphurization and the combustion air distribution ...... 16 5.4.4 NOx emission and the limestone injection...... 16 5.4.5 N20emission ...... 17 5.4.6Dust load ...... 17 5.4.7 Fouling of the boiler ...... 18 6 . KEMI POWER PLANT ...... 18 6.1 THE TESTPROGRAM FOR KEMIPOWERPLANT ...... 18 6.2 MEASUREMENTS,SAMF'LES AND ANALYSES ...... 19 6.3 PEAT QUALITY AND PROCESS VALUES ...... 20 6.4 TESTRESULTS...... 21 6.4.1 CdS-ratio and the desulphurization rate ...... 21 6.4.2 NO, emissions and the limestone injection...... 23 6.4.3 NH, emission ...... 23 6.4.4 N20 emission ...... 23 6.4.5 Effect of limestone injection on the dust load ...... 23 6.4.6 Fouling of the boiler ...... 24 7. TIE COST OF DESULPHURIZATION ...... 25 8. UTILIZATION OF THE END PRODUCT (FLY ASH) ...... 27 9. CONCLUSIONS ...... 28 10. DISCUSSION ...... 31

REFERENCES

APPENDIX 1. BACKGROUND

The Commission of the European Communities is reviewing the Large Combustion Plant Directive (LCPD). The third internal draft proposal for a Council Directive on Large Combustion Installations will be discussed with the Member States and industry in May. The draft outlines to limit the sulphur and nitrogen dioxide emissions from new solid fuel-fired power plants of over 300 MWh to a level of 200 mg/m3n (dry,6% 02). The emission limit would be linear so that when, the capacity of the plant decreases from 300 MWfi to 100 MW&, the emission limit increases from 200 to 600 mg/m3n. The emission limit value for installations of 100 - 50 MWh would be 850 mg/m3n. The Directive will also pertain to peat-fired power plants. The emission levels of the second draft proposal are presented in appendix 1. In Finland the current SO2 emission litvalue for new peat-fired boilers is 140 mg/MJ (appr. 360 mg/m3n). A Committee on Acidification is examining the necessary means to achieve the national target of reducing sulphur and nitrogen oxides emissions. An outcome of the work might be a proposal for new emission limit values for boilers, gas turbines and power plants.

Because there was not enough information available about the desulphurization of the flue gases fiom peat-fired fluidized bed boilers, a group of Finnish companies and Ministry of Trade and Industry decided to carry out a study to investigate the desulphurization of peat-fired boilers with limestone injection into the furnace. The boilers of the fluidized bed type were selected as the object of the study, based on the as- sumption that all the new peat-fired boilers would be bubbling fluidized bed or circulating fluidized bed boilers.

Desulphurization in pulverised and fluidized bed peat-frred boilers has been studied in 1992. (ETY Report 39/1992) /l/. The study proved that very high CdS (calciudsulphur) molar ratios were needed for SO2 reduction of over 40 %. Based on the study it is not possible to say what kind of emission values are achievable in the long run. 2. OBJECTIVES

The objectives of the project were to study

-how much it is technically and economically feasible to reduce the SO2 emissions in peat-fired fluidized bed boilers only by injecting limestone into the furnace, -how the limestone injection affects the other flue gas emissions, such as dust, nitrogen oxides (NO,) and nitrous oxide (N20), -whether a long term limestone injection causes fouling of the superheater surfaces or in the other parts of the process, -what are the costs of desulphurization, -how much the production of fly ash is increased due to added limestone injection and how the injection affects the utilization of the fly ash

Two peat-fired power plants, Kokkola and Kemi power plants, representing two different fluidized bed techniques were selected as target plants for the project. Both plants are equipped with limestone injection facilities. In this report, the test results of Kokkola and Kemi power plants are treated in separate sections.

3. THEORY OF DESULPHUREXTION

The limestone used in desulphurization processes normally contains 50 to 95-% of calcium carbonate (CaCO3). Calcium carbonate calcinates in the furnace at temperatures over 700 "C producing calcium oxide (CaO). This reaction is endothermal (consumes heat).

CaCO3 + CaO + COz

The formed CaO reacts with the SO2 and 02of the flue gas (sulphation). The reaction is exothermal (produces heat):

CaO + SO2 + %02 + Cas04

The efficiency of the desulphurization in the furnace depends on: - the partial pressure of SO2 in flue the gas - the quality of the limestone - the temperature in the furnace and - the limestone retention time in a certain temperature window.

The sulphation is a sur€ace reaction between CaO and SOz, which means that it is more effective when the partial pressure of SO2 is high (the S-content of the fuel is high). Generally, it can be said that the more porous the limestone is, the better it works in desulphurization. Geologically younger stones are normally softer and more porous than the older ones. Finnish limestones are normally old and hard, and they do not work in desulphurization as well as, for example geologically younger stones like Gotland (Sweden) limestone. The particle size distribution of the pulverised limestone also affects desulphurization efficiency. The type of the boiler determines the optimal particle size distribution. In circulating fluidized bed processes the optimal particle size is generally larger than in the bubbling bed or pulverized peat-fired boilers. the0 optimal temperature for desulphurization in furnace is about 840 'C. Above this temperature, less-than-optimum porosity forms, limiting the sulphation of the lime particles. The longer retention time the limestone particle has in a certain temperature window, the better the desulphurization rate obtained is /a.

4. FLUIDEED BED COMBUSTION

Fluidization and observations of phenomena related to fluidization have been refer- enced in the literature since the late 1800's. In the 1920's the fluidized bed technique was employed in so-called Winkler coal gasifier. The technique was patented in 1928. During the '60's a lot of development work for the fluidized bed technique was carried out in the UK and the USA. The first large commercial fluidized bed combustion unit was commissioned by Tennessee Valley Authority (USA) in 1977.

Nowadays fluidized bed combustion (FJ3C) is a widespread commercial combustion technique. The reasons for the success of this technique are, for example, the fuel flexibility and, normally, lower flue gas emissions than in pulverized fuel techniques. In the early '90's there were over 700 units in operation with a total thermal capacity more than 30 000 MW. Due to increasing concern of environmental aspects, the amount of FBC units is also increasing. The main fuel in the installed FBC boilers is coal, but also low grade fuels and wastes are widely used.

Fluidized bed combustion chamber contains a quantity of finely-divided particles such as sand or ash. The combustion air entering from below lifts these particles until they form a turbulent bed behaving like boiling fluid. Start-up burners heat the bed up to about 500 "C,and after that, any combustible material fed into the bed ignites almost immediately. The heat released as the material burns maintains the bed temperature, and the turbulence keeps the temperature uniform throughout the bed. The heat capacity of the solid bed particles gives the system thermal stability allowing variations in fuel properties like ash content, particle size and moisture.

In bubbling fluidized bed Combustion, shown in figure 1, the velocity of the rising air stream through the bed is about 1-3 m/s. The bed has a clearly defined upper surface, and is usually 70 to 110 cm deep. The coarse fuel bums in the bed, while the fines bum above the bed. HEAT EXCHANGeRs / \\

Figure I. Bubbling fluidized bed boiler (BFB).

The hot combustion gases burst through the surface of the bed, and pass through the freeboard above the surface to the heat-transfer surfaces. Solid particles carried with the gas flow are removed in a filter (baghouse or electrostatic precipitator) before the stack. In some cases the solid material is removed in the cyclone and recycled back to the fluidized bed.

In circulating fluidized bed combustion (CFBin figure 2 ), the upward velocity of the fluidizing air is at most 6-10 m/s. At this velocity the rising gas carries the bed solids along with it, and no upper surface is defined. The solids fill the entire combustion chamber, and the hot combustion gases carry the particles right out of the top of the chamber into a heavy-duty cyclone. The cyclone separates out the particles, which are re-circulated into the bottom of the main combustion chamber.

Figure 2. Circulating fluidized bed boiler (CFB) BFB suits best for combustion of reactive and high moisture fuels. Such fuels include for example, wood, bark, peat, straw, and waste sludge. It is also possible to co-fre fuels with lower reactivity, such as coal and graphite, but their share has to remain at appr. 40 % of the maximum. The fuel with high heat value may cause sintering of the bed material. No risks are involved in this combustion technique; on the contrary, it is quite flexible in view of the fuel grain and moisture. Compared with the BFB boiler, the CFB boiler provides effective desulphurization and long lag time in coal combustion. The investment costs of the BFB boiler are generally lower than the investments costs of the CFB boiler.

In certain cases, such as a moderatey low SO2 emission limit value, CFB mybe the only choice. Also, there is currently more commercial experience with CFB units on a wide range of unit capacities, stem cycles, and fuels. The important benefit of the BFB technique is that it can be used in retrofits in where the old boilers are modified for example from pulverized fired boiler to fluidized bed boiler. However, for most applications both BFB and CFB are technically feasible. Defining the lowestcost op- tion requires estimating capital and operating costs for each; the comparison will vary, depending on the unit capacity, steam cycle, fuel, sorbent, space requirements and emission limits.

4.1 Desulphurization in fluidized bed boilers

In FBC the flue gas emissions can be maintained at significantly lower levels than in conventional combustion techniques by different relatively simple emission control techniques.

Sulphur oxides can be reduced by 80 % or even more by limestone addition in fluidized circulating bed boilers. In bubbling bed boiler appr. 50 % SO2 reduction can be reached by limestone injection. Sulphur capture depends on fuel sulphur content and the fuel quality (higher sulphur content better relative capture), limestone reactivity, bed or furnace temperature, air distribution and solid material circulation. In the CFB boilers the limestone is injected into the furnace with the fuel or into the lower section of the furnace, whereas in the BFB boilers the limestone is injected above the bubbling bed. In the CFB boilers the fed limestone is recirculated back to the furnace, and to some extent used again, whereas the BFB boiler is a once-through system. Mainly because of these reasons, CFB boilers are in general more effective for sulphur capture than BFB boilers /3, 4, 5/. Table 1 presents different characteristics of CFB and BFB boilers. Table 1. The characteristics of CFB and BFB boilers.

Circulating fluidized bed boiler Bubbling fluidized bed boiler (CFB) Investment cost higher Investment(Bw cost lower Bed material, sorbent and fuel re- Normally once through system circulation Multi fuel boiler Multi fuel boiler Effective desulphurization by limestone Desulphurization efficiency of 50 96 injection (over 80 % desulphurization ef- achievable by limestone injection ficiencv) Limestone injection into the bed with the I Limestone injection above the bed I Long retention time of the sorbent I Short retention time of the sorbent Expensive in repowering applications More suitable for repowering of the old pulverized fuel boilers

5. KOKKOLA POWER PLANT

Kokkola power plant is located on the west coast of Finland, near the town of Kokkola. linatran Voima has been the owner of the plant since 1991. The tested peat- fired boiler and five oil-fired boilers generate electricity, district heat and steam to nearby industrial facilities of Outokumpu Zinc Oy and OMG Kokkola Chemicals Oy. Kokkola power plant also supplies energy for the Kokkola Energy Board.

The target boiler, boiler number 5, was commissioned in 1995. This F’yroflow Com- pact circulating fluidized bed boiler was delivered by A. Ahlstr6m Oy,a Finnish boiler manufacturer. The primary fuel source of the boiler is peat, but wood-based fuels and coal can also be used. The annual peat consumption totals some 0.5 million cubic metres. The boiler’s own steam flow amounts to 33 kg/s, and the boiler also su- perheats 17 kg/s of the zinc plant’s saturated steam. The live steam pressure of the boiler is 61 bar and, the temperature 510 OC. The heat output is 97 MW (108 MWh,l) and the total efficiency is approximately 90 %. The boiler is equipped with a limestone injection system. The limestone is fed onto the peat conveyors, and the mixture of peat and limestone is then injected into the lower part of the boiler. The peat dries and bums in the furnace, and the sulphur compounds of the peat are released into the flue gas. Circulating sand and some part of the other solid material, like unburned peat, is returned into the lower part of the boiler by cyclones. Fly ash is removed by a three field electrostatic precipitator. The fly ash precipitation efficiency is more than 99 %. A picture of the boiler number 5 is presented in figure 3 /6/. The probe

Figure 3. The cross-section of Kokkola circulating fluidized bed boiler.

5.1 The test program for Kokkola power plant

The test program approved by the management group of the project contained eight (8) different test runs. The fiist test run was carried out without any limestone injection into the furnace. The purpose of this run was to get the base level for the SO2 emission. The second run was made with Vimpeli limestone. The following 6 test runs were made with GS 500 limestone, which is a combination of Finnish Sipoo limestone and Swedish Gotland limestone. The calcium carbonate content of Vimpeli limestone was 55% on average (varies between 50-75 %) and GS 500 limestone 92- %. The particle size of both limestone types was 50-60 % under 120 pm. The particle size distribution curves for Vimpeli and GS 500 limestones are presented in appendix 2.

Desulphurization was tested with three different emission levels. One test was made with a partial boiler load, and in another test the distribution of primary and secondary combustion air was changed. Each test run was appr. six (6) hours long with the ex- pection of the air distribution test, which was appr. four (4) hours long. The last test before the long- term fouling test was made with the maximum limestone injection into the furnace. The test program is presented in appendix 3. The test runs were carried out between November 7-14,1996, and the fouling test continued until November 28,1996. The fouling test was executed at normal run of the boiler but at an emission level of 200 mg/m3n and using the GS 500 limestone. 5.2 Measurements, samples and analyses

During each test run, the value of following components of the flue gas were measured: 02, CO, S02, NO,. N20 and the dust load; all were measured six times. All the measurements were made in the flue gas duct after the flue gas fan. The gaseous (not N20) components were measured on-line, and the dust load was measured manually based on isokinetic suction (SFS standard 3866). For N20, the sample of the flue gas was taken manually and analysed on site by a gas chromatograph.

The on-line measurements were made with following instruments:

02: M&C PMA 25 (dry gas, paramagnetic analyzer) CO Ultramat 22P (dry gas, IR absorption) S02: Monitor Labs 8850 (wet gas, W fluorescence) NO,: Monitor Labs 8840 (wet gas, chemiluminescence)

Instruments were calibrated twice a day. To ensure the accuracy of the SO2 measurement, two parallel instruments were used, and the data was collected on two separate computers. The moisture content of the flue gas was determined by the dust load measurement. The measurements were carried out by NO’SEnvironmental Control Laboratory.

The process parameters were collected from the process computer of the plant (1 11 parameters). The fuel consumption was calculated based on the feed water supply and the live steam values. The limestone feed was determined based on the weight loss of the limestone silo during the test runs. Samples of peat and fly ash were taken each test day in each shift (three times a day). The peat samples were taken from the peat conveyor before the peat silo in the boiler room, and the fly ash samples were taken from the ESP silos (fields nos. 1 and 2). Five (5) different types of peat were used during the test. The water (ISO-1975-88) and the sulphur contents (SFS-5781) of each peat type were analysed daily. In addition, the ash (DIN 51719), volatile (DIN 51720) contents as well as the calorimetric heat value (ASTM D3286) were analysed, and the elementary analysis (Perkin-Elmer 2400) was made out of certain representative peat samples. Peat samples were analysed at Outokumpu Zinc’s laboratory and at the laboratory of the Technical Research Centre of Finland in JyviiskyE. In calculations, the analysis results of the Outokumpu Zinc laboratory have been used.

The limestone particle size distribution was measured by Foster Wheeler, Karhula (Malvern Laser Diffraction), and the calcium carbonate content of the limestone (ASTM 3682) was analysed by Nordkalk Parainen.

The CaO (AAS), S (Leco analyser) and the carbonate coal contents of the fly ash samples were analysed by Foster Wheeler Oy, Karhula. Free CaO (SFSEN-451-1) of the fly ash was analysed in NO’SEnvironmental Control Laboratory.

The fouling of the superheaters of the boiler was evaluated by a test probe. The probe was located after superheater number 8 (see picture 3). 5.3 Peat quality and process values

During each test run, the sulphur and the moisture contents of the peat were determined based on the weighted mean values of each test day. The peats used in the test were from five different peat bogs. The moisture and the sulphur contents of these peats varied from 35.8-58.9 % and 0.15-0.2 % (dry) respectively.

The average sulphur, moisture, ash and nitrogen contents of the peat of each test day are presented in table 2. The main process values are presented in table 3. Table 2. Sulphur, moisture, ash and nitrogen contents of the peat (Kokkola).

Date S-content, %, Moisture content, Ash content, % Nitrogen con- dry % tent, % 7.1 1. 0.17 49.21 3.88 1.59 8.11. 0.17 44.82 3.80 1.69 11.11 0.16 47.29 3.67 1.66 12.11 0.17 44.42 3.16 1.97 13.11 0.16 47.92 3.72 1.64 14.11 0.17 46.09 3.73 1.68 16.12* 0.17 46.00 amr. 3.75 aDDr. 1.69

Table 3. Main process values of each test run at Kokkola power plant (the target levels are in brackets).

1 16.12* 48.80 1 1.22 0.20 appr. 840 1 360(360) 1 * Values are based on normal operation of the boiler. 5.4 Test results

5.4.1 Cd-ratio and the desulphurization rate

The molar ratio of the calcium and of the sulphur flow into the furnace describes well the efficiency of the desulphurization of limestone injection. The higher the CdS ratio is, the lower is the sulphation rate of the formed CaO. The SO2 emissions of Kokkola power plant at different CdS molar ratios of Vimpefi and GS 500 limestone are pze- sented in figures 4 and 5 (SO2 in dry gas, 6 % 02).

SO2 emission I CdS-ratio Vimpeli Limestone (Kokkola)

200 500 180 400 160 m 140 2 E 120 3l 300 aE 100 &E

fn 200 80% 60 100 40 20 0 0 0123456789 cals

Figure 4. Emission levels and Cats molar ratios for VimpeJi limestone (KokkoZa).

SO2 emission I CalS-ratio GS 500 Limestone (Kokkola)

200 500 180 160 C 400 *) 140 2 E 'in 300 1x1a E E 100 g 200 60 100 40 20 0 0 0 2 4 6 8 101214 cas 1 Figure 5. Emission levels and CalS molar ratios for GS 500 limestone (Kokkolza). Figure 4 shows that the emission level of 360 mg/m3n (140 mg/MJ) is reached with Vimpeli limestone (CaCO3 content 55-%) at CdS-molar ratio 5.7 and the emission level of 200 mg/m3n (77 mg/MJ) with molar ratio 8.7. With GS 500 (CaCO3 content 92 %) limestone (figure 5), the equivalent CdS molar ratios are 2.3 and 10.7. The results with Vimpeli and GS 500 limestone are not fully comparable, because the bed temperature in the test with GS 500 was about 30 OC higher than in the test with the Vimpeli limestone. Also the CaCO3 content of Vimpeli limestone may have been more than 55-% (used in WS-ratio calculations) during the test which partly explains why the desulphurization with Vimpeli limestone seems to be better than with GS 500 limestone. One test was executed with GS 500 limestone with maximum feed. The emission level reached in that test was 93 mg/m3n at the Cd-molar ratio of appr. 13. The SO2 reduction efficiency reached was 80-%.

Table 4. CalS-molar ratios at emission levels 360 and 200 mgim3n

Limestone type Emission level 360 Emission level 200 wm3n mg/in3n Vimueli 5.7 8.7 I GS 500 2.3 I 10.7 I

In figure 6 the SO2 reduction rate versus CdS is shown (GS 500 limestone). A reduction of 55-60 % was needed to reach the SO2 emission limit of 200 mg/m3n.

SO2 reduction efficiency (Kokkola) 80 70 60 50 "Lo 40 30 20 10 0 0 5 10 15 cals

Figure 6,SO2 reduction eficiency versus CafS-ratio(GS 500 limestone). 5.4.2 Desulphurization and the bed temperature

The temperature of the furnace was measured at five different points. The average value of these measurements is considered as the bed temperature. The correlation of the CdS ratio and the bed temperature in the different test runs (GS 500 limestone, appr. 200 mg/m3n) is presented in figure 7. Even if the needed CdS-molar ratio does not follow the bed temperature exactly, it can be noted that desulphurization is clearly less efficient at higher bed temperatures.

CalS-molar ratio I bed temperature (200 mg/m3n, Kokkola)

820 830 840 850 860 870 temp. deg C

Figure 7. Correlation of CaIS ratio and the bed temperature (GS 500 limestone, emission level 200 mgtm3n).

5.4.3 Desulphurization and the combustion air distribution

In this test run the ratio of the primary and secondary combustion air was changed from 40/60-% to 5060-%. The idea was to reduce the bed temperature and to enhance the desulphurization process. When 50/50-% primaqdsecondary air was used, the Ca/S ratio was approximately 15-%smaller than with normal 40/60-% ratio. The total amount of combustion air varied from 37 to 39 m3n/s, depending on the boiler load and peat quality. Whether the combustion air staging had any effect on NO, emissions cannot be said based on the conducted test.

5.4.4 NOx emission and the limestone injection

The increase in the NO, emission due to limestone injection was not observed in the conducted tests. However, NO, emissions depend on the bed temperatures as shown in figure 8. The average bed temperature varied from 815 to 870 "C. The bed temperature is mainly a function of the moisture content of the peat and of the load of the boiler. The NO, emissions varied from 300 to 400 mg/m3n. The NO, emissions were relatively high at Kokkola power plant compared to Kemi power plant (appr. 200 mg/m3n) although the nitrogen content of the peat used was lower in the Kokkola case than in the Kemi case.

NOx emissionslbed temperature (Kokkola)

81 0 830 850 870 temp. deg. C

Figure 8. NOx emissions and bed temperature.

5.4.5 N20 emission

The N2O emission of the boiler was measured manually on four test days. The NzO value was between 4.5-7.0 mg/m3n in those runs where limestone injection was on. On the first test, day without limestone injection the NzO value was 70 mg/m3n. On the first test day, the bed temperature was lower than on the other test days, which explains the elevated NzO values.

5.4.6 Dust load

The dust emission after the electrostatic precipitator was measured in five test runs. In each test run the dust emission remained constant, at 2-3 mg/m3n. The electrostatic precipitator (ESP) of Kokkola power plant is designed for coal burning, and is for that reason oversized for peat burning which explains the low dust emission levels during the tests. In Kokkola case the run with the SO2 emission level of 200 mg/m3n increased the amount of the produced fly ash for 47-% (0.227 kg/s to 0.334 kg/s, calculated values) from normal run (SO2 level 360 rng/m3n). The fly ash load without limestone injection is 0.18 kg/s (appr. 3.0 g/m3n). The handling of the fly ash was aggravated because of the high fiee calcium oxide content. 5.4.7 Fouling of the boiler

The fouling of the boiler, due to the increased limestone injection was studied by a test probe which was installed after superheater number 8 (see figure 3). The probe was a one-inch thick uncooled steel bar. Approximately one meter of the bar was in- side the boiler in a heavy dust flow for 16 days. During this fouling test, the SO2 emission level was kept constant, 200 mg/m3n, so the limestone flow into the boiler was about two times greater than running the boiler with the normal emission level of 360 mg/m3n. After the test period, the probe was removed and photographed. Only about one millimetre thick layer of deposit was observed on the probe. The deposit layer was easy to remove. The picture of the probe is in appendix 4.

Also the pressure drop over the combustion air preheater and the feed water heater (economiser) was measured on-line during the entire test period. No indication of boiler slagging or fouling could be found in the measurements.

6. KEMIPOWERPLANT

A new bubbling fluidized bed (BFB) boiler at Veitsiluodon Voima Oy's Kemi power plant, delivered by Kvaerner Pulping Oy, was chosen for the limestone (CaCa) injection tests. The main fuels in the boiler are bark, peat and sludge from the biological effluent treatment plant of the pulp mill. The nominal power output of the plant is 267 MWh,l. The nominal steaming capacity of the boiler is 95 kg/s. The boiler is equipped with a limestone injection system and with an electrostatic precipitator (ESP). The boiler was commissioned in November 1996, and it produces electricity, heat, and process steam to Enso Oy, Kemi Mills. The desulphurization test was the first time when the limestone feeding system was operated with SO2 measurement. The feeding system was not optimized, eg. regarding limestone mixing in the furnace. A cross- section view of the BFB boiler is shown in Figure 9. In bubbling fluidized bed (BFB)boiler limestone is injected above the bed. Therefore the particle size of the limestone must be significantly smaller to achieve a high reduction efficiency. In BFB boilers, in-bed desulphurization has only marginal effects, and the bed temperature does not have any significant effects on the desulphurization process.

6.1 The test program for Kedpower plant

Limestone injection tests were conducted between December 9-13, 1996. Each test run was appr. two hours long. During the test period, the steam consumption at the Enso Oy Kemi Mills was at its maximum almost all of the time. Therefore, the load of the boiler could not be adjusted according to the preliminary test plans. All the test points in the schedule were supposed to be carried out in constant conditions, but because the boiler is controlled according to the steam consumption of the mill, the load could change during each test run. Therefore, average process values are used in all the calculations. The fulfilled test plan is presented in appendix 5.

Limestone, commercially labeled as TYTYRI G, €tom Nordkalk Oy Ab, was used in the tests. TYTYRI G (Limestone G) limestone is Swedish Gotland limestone ground in Finland. Its CaCO3 content is at least 97 % and over 90% of the particles are smaller than 90 pm. All these values were given by the supplier and were used in the calculations.

.The probes

Figure 9. The cross-sectional view of the Veitsiluodon Voima Oy, Kemi BFB boiler.

6.2 Measurements, samples and analyses

During each test run, concentration of the following components in the flue gas were continuously measured 02, CO, C02, S02, and NO,. Nitrous oxide (N20) and ammonia (NH3) were measured at each test point with an FTIR analyzer, but not on-line. All gaseous components were measured in the stack. The gas samples for SO2 and NO, analyses were collected with an EPM dilution probe. The dust load was measured before and after the ESP at each test point. The dust load was measured manually based on isokinetic suction (SFS standard 3866). The on-line measurements were made with the following instruments:

02: IR-2200(dry gases, KOH solution) CO, C02: IR-702(dry gases, IR absorption) SOz: AF 20 M (wet gases, UV fluorescence) NO,: Environment AC 30 M (wet gases, chemiluminescence) NH3, N20 Gasmet lT-IR analyzer (dry gases, IR absorption) Dust: STL-Maxi particle collector Instruments were calibrated at least once a day and whenever needed. The wet content of the flue gas was determined by the dust load measurement. All the measurements were carried out by the University of Oulu, Laboratory of Energy and by Prosensor Oy-

The process parameters were collected from the process computer of the plant. The fuel consumption figures are based on the on-line measurement system in the plant. The limestone feed rate was based on the level measurement of the limestone silo during the test runs. However, this system appeared to be very inaccurate and therefore limestone feed rate was also checked by manual measurement. In spite of these measures, a certain uncertainty is connected to the limestone feed rate numbers.

Samples of peat and fly ash were taken at each test point. The peat samples were taken from the peat conveyor before the rotary feeder in the boiler room, and the fly ash samples were taken from the ESP silos (field no. 1). The CaO, S and the carbonate contents of the fly ash samples were analyzed by Libmen Laboratoriot Oy.

6.3 Peat quality and process values

The peat used in the test came from one peat bog. Fuel samples from the peat were collected at least once a day. However, during most of the days several fuel samples were collected. Moisture and ash contents in the peat were analyzed (LECO SC-132) immediately after collecting at Enso Oy Ked Mills laboratory. Sulphur content of the peat was analyzed after the tests at Vapo Oy laboratory. Table 5 shows sulphur, ash, and moisture contents in the peat during different tests. Average values of all the samples are also shown. According to the analysis, the quality of the peat has been quite constant. The average moisture and sulphur content in the peat were 51.7 and 0.25 % (dry), respectively. The average nitrogen content in the peat was 3.0 % in dry solids. The on-line measurements were made with the following instruments:

02: IR-2200(dry gases, KOH solution) CO, COZ:IR-702 (dry gases, IR absorption) SO2: AF 20 M (wet gases, UV fluorescence) NO,: Environment AC 30 M (wet gases, chemiluminescence) NH3, N20: Gasmet FT-IR analyzer (dry gases, IR absorption) Dust: STL-Maxi particle collector

Instruments were calibrated at least once a day and whenever needed. The wet content of the flue gas was determined by the dust load measurement. All the measurements were carried out by the University of Oulu, Laboratory of Energy and by Prosensor Oy.

The process parameters were collected from the process computer of the plant. The fuel consumption figures are based on the on-line measurement system in the plant. The limestone feed rate was based on the level measurement of the liestone silo during the test runs. However, this system appeared to be very inaccurate and therefore limestone feed rate was also checked by manual measurement. In spite of these measures, a certain uncertainty is connected to the limestone feed rate numbers.

6.3 Peat quality and process values

The peat used in the test came from one peat bog. Fuel samples from the peat were collected at least once a day. However, during most of the days several fuel samples were collected. Moisture and ash contents in the peat were analyzed (LECO SC-132) immediately after collecting at Enso Oy Kemi Mills laboratory. Sulphur content of the peat was analyzed after the tests at Vapo Oy laboratory. Table 5 shows sulphur, ash, and moisture contents in the peat during different tests. Average values of all the samples are also shown. According to the analysis, the quality of the peat has been quite constant. The average moisture and sulphur content in the peat were 51.7 and 0.25 % (dry), respectively. The average nitrogen content in the peat was 3.0 % in dry solids.

The quality of the peat appears to be very constant during the tests, and variations in the results due to the fuel are therefore minor. The main process values are presented in Table 6. Tdle 5. Sulphur, ash, moisture and nitrogen contents of peat during the Kemi BFB tests.

Table 6. Main process values during the Kemi BFB tests.

I 13.12 I 21.5 I 60.0 I 0.20 I 391 I

6.4 Test results

6.4.1 Ca/S-ratio and the desnlphurization rate

The average sulphur content of peat in these tests wa 0.25% in dry dids. If all of the sulphur in the fuel is released as S02, it would produce emissions of around 580 mg/m3n in dry gases (6% 02). Since peat ash contains some calcium, part of the sulphur in the fuel is readily bound to CaSO,. According to calculations and measurements, around 10% of the fuel-sulphur is bound with the fly ash calcium. The measured SO2-level was 520 mg/m3n in dry gases (6% 02) on average, without additional limestone feeding.

The effect of limestone addition on the S02-level can be seen in figure 10. The SO2 reduction efficiency in the tests is presented in figure 11. The maximum WS-ratio used in the tests was 9.7. A relatively rapid reduction in the SOZ-levels occurs after the adding of limestone. A CdS-ratio of about 3.0 is needed to achieve the 360 mg/m3n (140 mg/MJ) emission limit. However, increasing the limestone feeding rate (and CdS-ratio) seems not to decrease emissions significantly. The maximum reduction level of 45-47% is achieved with a CdS-ratio of 6.0-7.0. The off-levelling phenomenon in the figure is most probably due to the insufficient mixing of the limestone in the flue gases. The emission level of appr. 280 mg/m3n (appr. 110 mg/MJ) was the lowest level reached in these tests.

SO2 emission I CalS ratio (Kemi)

600 220 500 200 180 8 400 1 60 .E 1 40 300 120 cu- 100 8 200 80 60 100 40 20 0 0 0 2 4 6 8 10 CalS

Figure IO. The eflect of CalS-ratio on the SO2 emission level.

SO2 reduction efficiency (Kemi)

50 45 40 35 30 % 25 20 15 10 5 0 0 2 4 6 8 10 CdS

Figure 11. SO2 reduction eflciency versus CalS-ratio. 6.4.2 NO, emissions and the limestone injection The average 3.0% fuel-N content in the peat would produce NO, emissions of around 11 0o0 mg/m3n in dry gases (6% 02). However, the average measured NO, emissions were of the order of 200 mg/m3n in dry gases. This would mean that only 1-2% of the fuel-N is forming NO, during combustion. The main reason for this is effective air staging in the furnace.

According to the tests, limestone injection did not seem to affect the NO, level. The most critical factor affecting the level of NO, emissions is the state of air staging. No detailed study, however, on the effects of air staging to NO, emissions from the boiler was carried out in this test series.

6.43 NH3emission Since peat contains relatively high amounts of nitrogen, and the atmosphere in the bed in BFB boilers is slightly reducing (sub-stoichiometric), some formation of ammonia (NH3) may occur. Therefore, ammonia emissions were measured during the tests. The average NH3 levels were between 3-8 mg/m3n (wet gases) during the tests. Occa- sionally, the values were peaking up to 12 mg/m3n. Limestone injection appeared not to have any significant effect on the NH3 emissions.

6.4.4 N20 emission As a consequence of the low bed temperatures and the efficient NO, reduction efficiency, some nitrous oxide (N20) formation may occur in CFB and BFB boilers. However, in a BFB boiler and, especially with peat firing, only a minor portion of the incoming fuel will find its way into the bed. Most of the peat is combusted over the bed in a dense suspension. The bed operates sub-stoichiometrically and a large portion of fine fuel and gasification products bum above the bed in high temperature. Because of the high temperature in the freeboard, N20 emissions from BFB boilers are usually low.

Nitrous oxide emissions were measured from the stack at every test poinL The average N~Oemissions with peat were between 4-10 mg/m3n (dry gases). The maximum measured values were 30 mg/m3n. No clear correlation to the limestone feeding could be observed.

6.4.5 Effect of limestone injection on the dust load The most obvious effect of the limestone feeding is the increase in the fly ash content. The fly ash content was measured before and after the electrostatic precipitator (ESP). The normal dust load without limestone injection with peat firing was around 5-6 g/m3n. The dust content after the ESP was of the order of 1-2 mg/m3n with and without limestone feeding.

The limestone feeding rate varied between 0.2 kg/s and 0.9 kg/s in the tests. The fly ash content and the limestone feeding rate were directly proportional to each other. With maximum limestone feeding rate, the dust content in the flue gases was doubled to 11-12 g/m3n. However, the dust load after the ESP was not affected, remaining on the 1-2 mg/m3n level. The ESP of the Kemi power plant is designed for use of fuel containing greater amounts of ash than peat which means that the ESP is oversized for cleaning the flue gas from peat firing. Some uncertainty in the measuring of the limestone feeding rate may have influenced the achieved results. Figure 12 shows the trend in the flue gas dust content as a function of limestone feeding rate.

Dust load I limestone feeding rate (Kemi) 14 12

10 -5E 0 m 26c u) $4 2 0 0 200 400 600 800 1000 Limestone feeding rate, gls

Figure 12. The efSect of limestone feeding rate on the flue gas fly ash content before ESP.

6.4.6 Fouling of the boiler

The fouling propensity of limestone addition was measured with air-cooled deposit probes. The test times, however, were so short that no clear picture of the fouling be- haviour could be made during the tests. Some decrease in the steaming capacity was, however, discovered during the tests. In a subsequent scheduled outage after the tests, the boiler was inspected, and heavy fouling was discovered in the superheater region. Deposit samples were collected and analyzed. Alkali silicates found in the samples were probably the cause for the deposits found in the boiler. The increased powder load in the boiler during the test may have increased the growth of the deposits. The Kemi boiler was fired with waste sludges and bark between the test runs. This has most probably caused the fouling found in the boiler superheater region. 7. THE COST OF DESULPHURIZATION

In the cost calculations it has been assumed that the price of the limestone at the site is 270 Wtonne. This price is considered as an average price of limestone in Finland according to the limestone supplier. The calcium carbonate content used in the calculations was 92-%. The investment costs calculations are based on the idea that the dust load to the ESP is increased because of limestone feeding and the additional field is normally needed to keep the particulate emission levels at a certain level. In a case of emission level of 360 mg/m3n the investment only contains the cost of the limestone feeding facilities.

The costs of desulphurization with limestone injection into the furnace were estimated for Kokkola type circulating fluidized bed (CFB) boiler with three emission levels. In the calculations, the WS-molar ratio of 2.5 was used for an emission level 360 mg/m3n (140 mg/MJ, current situation), WS-molar ration of 6 was used for an emission level of 260 mg/m3n (appr. 100 mg/MJ) and CdS-molar ratio 10 for an emission level 200 mg/m3n (appr. 77 mg/MJ, the draft proposal for a new directive).

The costs were also estimated for Kemi type bubbling fluidized bed (CFB) boiler by using two emission levels. In the calculations the WS-molar ratio of 3.0 was used for an emission level 360 mg/m3n and WS-molar ratio 7.0 for an emission level 280 mg/m3n (appr. 110 mg/MJ, the reached level). In the case of an emission level of 280 mg/m3n the investment cost includes one additional field for ESP

The desulphurization costs for both boiler types were calculated also at an emission level of 200 mg/m3n in the case of having the semi-dry desulphurization system.

The results of the cost calculations are presented in table 6 and figures 12 and 13 as Wremoved SO2 tonne. Also the marginal cost of desulphurization when reducing the emission from 360 to 200 mg/m3n (Kokkola) and from 360 to 280 mg/rn3n (Kemi) are presented in the table 7. Table 7. The results of the cost calculations.

Kokkola Power Plant I Kemi Power Plant Emission level, mg/m3n 360 260 200 i6:0 Desulpurization cost 7900 9200 10800 with limestone injection, reached WtSO., Desulphurization cost with semi-dry desulphurization system, mM/ts02 The marginal cost of the 12 600 16 100 desulphurization (360 ->200, Kokkola; 360 ->280, Kemi), MtS02

The detailed cost calculations are presented in table form in appendix 6. The utility costs contains the limestone costs, boiler power loss (because of calcination) and ash disposal costs. In the Kemi case, the autoabsorption of 10 % has been taken account in cost calculations. In the Kokkola case the autoabsorption was not observed.

Desulphurization costs [FIWtS02] Case: Kokkola

-“uv’ 40-“uv’ 000

350W. 30350W. OW .“J I ’ B 25000 Maintenance 200w 8 15 000

in nnn

Limestone Limestone Limestone Semidry injection injdon injection 200 mgm3n 360 mq‘m3n 260 mq‘m3n 200 mq‘m3n Desulphurlzatlon method &emission limit Figure 13. Desulphurization costs FIMItSO2, Kokkola power plant. Desulphurizationcosts [FIM/tSO2] Case: Kern1

45 000

40 000

35 000

30 000 B 25000 39 i 2oooo 15 000

10 000

5 ow

0 Limestone Limestone Semidry injection injection 200 mglm3n 360 mglm3n 260 m@rn3n Desulphurizatlonmethod ii emlsslon llmlt Figure 14. Desulphurization costs, FIMItSOZ, Kemi power plant.

The big difference in desulphurization costs between Kokkola and Kemi power plants in a case of Semi-dry desulphurization system is caused mainly by the different ca- pacty of the plants and the S-content of the peat (higher s-content means lower desulphurization costslremoved SO2 tonne).

For comparison the cost calculations were carried out for four different hypothetical peat-fired boilers. In those calculations the sulphur content of the peat was assumed to be 0.2 %. The desulphurization costs of CFB and BFB boilers of capacity of 100 and 300 MW were calculated. The calculations showed that the cost of the desulphurization is strongly affected by the emission level and the sulphur content of the peat. The differences in desulphurization costs between boiler types or boiler capacities were found not to be significant. The results of the calculations are presented in appendix 7.

8. UTILIZATION OF THE END PRODUCT (FLY ASH)

The fly ash from peat-fired power plant is currently used in land filling. As a result of increased limestone feeding, the quality and the quantity of the produced fly ash changes.

The Kokkola power plant produces at the emission level of 360 mglm3n (140 mg/MJ) appr. 8 000 tonnes of fly ash. At the reached emission level of 200 mg/m3n, the produced fly ash amount increased by 47-%, which would mean an annual fly ash production of appr. 11 000 tonne. The Kemi power plant produces appr. 17 000 tonnes fly ash annually without limestone feeding. Generally speaking, the amount of limestone feeding needed for reaching the emission level of 200/280 mg/m3n will approximately double the produced fly ash amount as compered to the situation of running the boiler without limestone feeding in both the Kokkola and the Kemi cases.

The quality factors of peat fly ash at an emission level of 360 mg/m3n and the fly ash from desulphurization tests (200 mg/m3n emission level) are presented in a table 8.

Table 8. The quality factors of the peat fly ash.

When the free calcium content of the fly ash increases from 9 to 20 percent the strength of the ash decreases respectively. The elevated amount of free calcium may cause problems in land filling because of excessive expanding of the fly ash. There might be, however, new market opportunities for the peat fly ash with high calcium content. It can be used as stabilizer in a method called deep mixing. In this method, stabilization is done by installing columns in soft soil. Normally, lime is used as a binding agent in deep mixing. High calcium content in the ash is beneficial for this purpose. The market for this kind of stabilizer is limited to 10 O00 tonneda. The stabilizer material must be storaged in silos in oder to keep it dry.

9. CONCLUSIONS

In this project, the effect of limestone feeding on S02, NO,, NH3 (BFB only), N20, dust emissions and the boiler fouling of peat-fired circulating and bubbling fluidized bed boilers was studied. The economy of the desulphurization and the utilization rate of the produced fly ash were also investigated. The tests were executed at Kokkola power plant and Kemi power plant. The Kokkola power plant represents a circulating fluidized bed and the Kemi power plant a bubbling bed technique.

At Kokkola power plant the emission level of 200 mg/m3n with GS 500 limestone (CaCO3-cont. 92-%) was reached at a CdS-molar ratio of 10.7. The SO;?reduction rate was around 60-% at the emission level of 200 mg/m3n. The maximum SO2 reduction rate reached with GS 500 limestone was 80-%.

At Kemi power plant the lowest emission level reached was appr. 280 mg/m3n at the CdS-molar ratio of 6.0-7.0.The reached SO2 reduction efficiency varied between 45 and 47-%. The reasons for the relatively low reduction rates are most probably the insufficient mixing and the short retention time of limestone in the furnace. The desulphurization in the circulating bed boiler (Kokkola) is strongly affected by the bed temperature which is a function of the moisture content of the peat, primary and secondary air distribution and the boiler load. In the bubbling bed boiler, (Kemi) the bed temperature stays relatively constant, regardless of, for example, the peat quality.

Emissions of NO, or N20 were not elevated due to limestone feed either at the Kokkola or Kemi power plant. However, at Kokkola both of these emissions are related to the bed temperature. The higher the bed temperature the higher the NO, emissions and the higher the bed temperature the lower the N20 emissions.

The electrostatic precipitator (ESP) of Kokkola power plant is designed for coal burning and is for that reason oversized, for peat burning. The ESP of Kemi power plant is also oversized due to use of other fuels than peat such as sludges and other waste fuels. At the Kokkola and the Kemi power plant the dust emission after the ESP stayed constant (Kokkola 2-3 mg/m3n, Kemi 1-2 mg/m3n) during the test. Because the unreacted CaO content in fly ash was high during the test at lower emission levels, (appr. 20-%), the fly ash was more difficult to handle (unload from silo and transfer) than normally. If the higher limestone feeding rates are used special attention needs to be directed to the safe fly ash handling. The running of the boiler with the emission levels of 200 (Kokkola) and 280 mg/m3n (Kemi) approximately doubled the produced fly ash amount.

The fouling of the boiler at the Kokkola power plant was studied with the test probe which was installed after the superheater region. Also the pressure drop over combustion air preheater and economiser was observed during the test. No indication of boiler slagging or fouling because of elevated limestone feed was found.

At the Kemi power plant, the fouling propensity of the limestone addition was studied with air-cooled probes. No fouling during the short time tests was observed. In the scheduled outage after the test the boiler was inspected, and heavy fouling was discovered in the superheater region. The Kemi boiler was fmd with waste sludges and bark between the test runs which most probably has caused the fouling.

The desulphurization cost in the Kokkola power plant case is appr. 7 900 FIM/removed SO2 tonne at an emission level of 360 mg/m3n and appr. 10 800 Wremoved SO2 tonne at an emission level of 200 mg/m3n.

In the Kemi case the CdS-molar ratio of 3.0 was used in calculations for an mission level of 360 mg/m3n and WS-molar ratio 7.0 for an emission level of 280 mg/m3n (1 10 mg/MJ, the reached level). In a case of an emission level of 280 mg/m3n investment cost includes one additional field for ESP. The desulphurization cost in the Kemi case is appr. 8 400 Wremoved SO2 tonne at an emission level of 360 mg/m3n and appr. 11 600 Wremoved SO2 tonne at an emission level of 280 mg/m3n.

The desulphurization costs for both boiler types were calculated also at an emission level of 200 mg/m3n in a case of having the Semi-dry desulphurization system. The desulphurization cost in the Kokkola case is 40 O00 FIM/removed SO2 tonne and in the Kemi case 19 000 FIM/removed SO,. The big difference in desulphurization costs between Kokkola and Kemi power plants in a case of Semi-dry desulphurization system is caused mainly by the different capacity of the plants and the S-content of the peat (higher S-content means lower desulphurization costdremoved SO2 tonne).

The fly ash utilization possibilities were also studied. It is not sure if fly ash with the high free CaO level is useable for land filling material. However it may be used as stabilizer in deep mixing.

The main results of the project are presented in table 9.

Table 9. Main results of the Desulphurization in Peat Fired Circulating and Bub- bling Fluidized Bed Boilers project.

Fouling of the boiler No significant fouling observed Significant fouling in superheater area observed in the scheduled outage after the test (most probable reason: sludge

Cost of desulphurization, 200 40 OOO FIM/S02 tonne mg/m3n, semi dry method (notice the capacity of the boilers and S-content 10. DISCUSSION

The results of the conducted tests support the theory of the desulphurization in the CFB and BFB boilers. It is possible to reach an SO2-removal efficiency of 80-% with limestone injection in a peat-fired CFB boiler and an SO2-removal efficiency of about 50-% in a BFB boiler. In the CFB boiler the SO2 emission level of 200 mg/m3n is possible to achieve. The lowest achieved SO2 emission level in the BFB boiler is about 280 mg/m3n (1 10 mg/MJ).

Today and in the future both fluidized bed techniques should be available for feasible commercial use. Even if the desulphurization in a CFB boiler is more efficient and cost-effective than in a BFB boiler, the BFB has certain considerable benefits as compared to the CFB boiler, such as better applicability to the repowering applications and to the industrial power generation. The SO2 emission level of approximately 280 mg/m3n (1 10 mg/MJ) is possible to reach both in CFB and BFB. The CdS molar ratios needed to achieve the mentioned removal efficiencies seem not to be significantly related to the limestone type. Theoretically, the nitrogen oxides (NO, or N2O) emissions should be increased, due to the increased limestone feeding. This kind of phenomenon, however, was not found. It is obvious that some elevation of the nitrogen oxides occurs, due to the increased limestone feeding, but the phenomenon is difficult to observe, because the other vari- ables (furnace temperature, peat quality etc.) affect the formation of the nitrogen oxides, too.

The study showed that limestone injection into the furnace does not increase the fouling of the water walls or the superheater region in the CFB. When the BFB boiler was inspected during an outage after the study, a heavy fouling was discovered in the superheater region. The deposit was analysed and alkali silicates were found in the deposit which have probably caused the fouling. The origin of the alkali silicates is mainly the sludge which was fred between the peat test runs. The role of the limestone feeding in the fouling of the BFB is not clear on the basis of this study. An additional long-term study is required to clarify the fouling of the BFB boiler.

The desulphurization cost per removed SO2 tonne is not depending on the boiler capacity but is very strongly related to the SO2 emission level. The desulphurization cost is, to certain extent, related to the boiler technique. In Finland the current emission limit value is 360 mg/m3n. The limitation of the SO2 emissions from 360 mg/m3n to 280 mg/m3n will approximately double the annual costs of the desulphurization in the CFB and BFB boilers.

Today, the fly ash from peat firing (emission limit value 360 mg/m3n, the free CaO content appr. 9%) is used in land filling. The free CaO content in fly ash, the produced fly ash amount and the limestone feeding rate are directly proportional to each other. The fly ash with a high (appr. 20 %) CaO content may not be utilized for land filling because of its excessive expanding. The fly ash with high CaO content may be useable as stabilizer in deep mixing (stabilization of boggy or watery soil). In Finland, the market for this kind of stabilizer is limited to 10 OOO tonneda, which means that the fly ash production of one 100 MW&power plant operating at an emission level of 200 mg/m3n would saturate the stabilizer markets. If the produced fly ash with high a CaO content cannot be used in landfilling or for other commercial application the ash disposal would increase the desulphurization cost significantly. REFERENCES

1. ETY Report 39/1992 2. Kouvo, P; Pyykkonen, A, Kaukanen, E, Desulphurization with lime and catalyst of flue gases from combustion of heavy fuel oil in small boilers. Enconsults, Turh, Finland 1990.

3. Hupa, M Bostrom, S, Fluidized Bed Combustion; Prospects and Role. Ab0 Akademi, Turku, Finland 1991.

4. Raiko, M,NO’S Use of AFBC with Low-Grade Fuels for Energy Generation. IVO International, Vantaa, Finland.

5. Singer, J.G, Combustion Fossil Power. Combustion Engineering Inc, Windsor, Connecticut, USA 1991

6. Imatran Voima Oy, Brochure of Kokkola power plant.

APPENDIX

Appendix 1: The proposal for new Council Directive Appendix 2: The limestone particle size distribution curves Appendix 3: The test program for Kokkola Appendix 4 The picture of the fouling test probe Appendix 5: The test program for Kemi Appendix 6: The desulphurization costs calculations for Kokkola and Kemi power plants Appendix 7: The desulphurization cost calculations for 100 and 300 MW CFB and BFB boilers Draft Proposal for a new Directive on Large Combustion Installations, 3rd Draft, April 1997 ANNEX In Methods of rneasurernenr of emissions and Determination of the tod annual emissions for new and exisdng installations ANNEX IV

burnhg solid hels and expressed in rnflrn’ (02 con ten^ 6%) 9011umtS > 300 m-th 300 - 100 MWrh 100 - 50 MWh 600 so2 200 200 to 830 (linear increase tiom 300 to Mwth) I 100 I Nox 200 200 400 3 Dust 30 30 50

Air emission lknir values for new installations burning liquid fuels and w-pressed in mg/?Vm3 (02 conrent 3%) Polluuvlrs > 300 Mw6 300 - 100 MWh 100 - 50 MU& SQ2 200 200 fo 600 850 (linear incteax fi0m 300 00 100 Mwh) I NOX 1 200 I 200 400 : Dun I 30 I 30 I- 50

natural gas 35 liquefied gas 5 so2 coke oven gas 1100 blast furnace gas 200 Othu gases 35 mm 100

NOx natural gas 100 I orher gases 200 PARTICLE SIZE ANALYSIS 30.1,1997

METHOD: SIEVMG: fraction above 0.125 mm MALVERN LASER DIFFRACTION : fraction below 0.125 mm

Order code : U961107 Sample code: LV02 Project : IVO KOKKOLA Sample : LIMESTONE Run : Date: Time: Remarks: MG 5

0 1 100 1 10 Particle diameter prn 1000 10000 i SIEVE ON SIEVE PASSED THE MALVERN MBAND PASSED mm YO SIEVE Yo mm . Yo YO 14.000 - - 0.056 15.5 34.1 10.000 - 0.022 9.2 24.8 8.000 - - 0.010 6.9 18.0 6.300 - - 0.004 8.4 9.6 4.000 0 .o 100.0 0.002 .6.1 3.4 2.000 0.1 99.9 1.400 - - 1.000 2.3 97.6 0.710 4.6 93.0 0.500 8.9 ’ 84.2 0.355 8.1 76.1 0.250 9.2 66.9 0.180 - 0.125 17.3 49.6 0.090 0.000 49.6

Proprietary Information L. .- #-. - APPENDIX 2/2

PARTICLE SIZE ANALYSIS 30.1.,997

METHOD: SIEVING: hction above 0.125 mm MALVERN LASER DIFFRACTION : fiaction below 0.125 mm

Order code : U96/107 Sample code: LVO 1 Project : IVO KOKKOLA Sample : LIMESTONE Run : Date: 11.11.1996 Time: Remarks: GS 500 (ruokintakalkki)

1 10 100 Particle diameter pm 1000 10000

SIEVE ON SIEVE PASSED THE MALVERN INBAND PASSED mm YO SIEVE Yo mm YO YO 14.000 - - 0.066 15.5 30.2 10.000 - p.04 1 7.0 23.2 8.000 - - 0.0 19 7.0 16.2 6.300 - - 0.008 8.4 7.8 4.000 - - 0.003 .4.6 3.2 2.000 0.0 100.0 1.400 - - 1 .ooo 1.2 98.8 0.710 - 0.500 7.3 ’ 91.4 0.355 6.9 84.5 0.250 9.3 75.2 0.180 0.125 20.0 55.2 0.090 9.5 45.7 0.000 45.7

Proprietary Information KOKKOLAN POWER PLANT DESOX TEST 4-28.1 1.1996 Date Load (YO) Emissions (mg/MJ) Limestone Measurements 4.1 1. 100 base level Vimpeli Installation of the measurements esuhments ~ 5.11. 0 - I boiler down ~ --I 6.11. 0 ' .. - 7.11. 100 base level

9.11. normal run - change of the - limestone 10 11. normal run - GS 500 - 11.1 1 100 140 GS 500 02, CO, S02,NOx, N20, dust 12.1 1. 100 70 GS 500 02,CO, S02, Nox, N20, dust 13.1 1 100 100 GS 500 02, CO, S02, NOx, dust 13-14.1 1 partial load 70 GS 500 02, CO, S02, NOx 14.1 1 100 (max distr.) 70 GS 500 02, CO, S02,NOx 14.1 1 100 (max limestone 70 GS 500 02, CO, S02,NOx

14.1 1 normal Nh' 70

15-28. . normal rcul 70

APPENDIX 5

Date

9.12.-96 Demonstration runs with the limestone injection system. Tune-up of the boiler and measuring systems. 10.12.-96 +100% Peat Base level 95.0 a140 YES

1 1.2.-96 85.0 lOOY0 Peat 140 YES

90.0 1minimum I YES 60.0 Base level 13.12.-96 No 140 I YES 65.0 minimum I YES DESULPHURIZATION OF PEAT FIRED BOILERS1

COST CALCULATIONS I I I I ICASE:KOKKOLA CFB-BOILER

Emission limit mglm3n 360 260 200

Basic data Investment kFlM I 000 2 000 2 ooa Boiler power MVW 97 97 97 Annual oeak ooeratina time h 5 000 5000 5 ooa Rate % 7 7 7 Period a 15 15 15 Maintenance cost (2% of investment) kFIM/a 20 40 40

Prices Limestone price FlMA 270 270 27a Cost of thermal power loss FIM/MWh 40 40 40 Cost of ash disposal FIM/t 40 40 40

Emissions SO2 emission without desulphurization t/a 329 329 329 SO2 emission with desulphurization t/a 258 186 143 Removed SO2 amount tla 72 143 186

Utility consumption Ca/S molar ratio mol/mol 2.5 6 10 Limestone t/h 0.28 0.672 1.11 Boiler power loss kW 54 260 456 Ash disposal t/h 0.25 0.52 0.78

Limestone I kFIM/a 378 I 907 I 1 499 Boiler power loss kFIM/a 11 52 91 Ash disposal kFIM/a 50 104 156 Total kFlM/a 439 1 063 1 746 ~~~ ~ ~~

TOTAL ANNUAL COSTS Investment kFIM/a 110 220 220 Maintenance kFIM/a 20 40 40 Utilility kFIM/a 439 1 063 1 746 Total kFlM/a 569 I323 2 005

Investment FI MAS02 1 533 1 533 1179 Maintenance FIMASO2 279 279 215 Utilility FIMltS02 6 128 7 424 9 376 Total FIMRS02 7 940 9236 I0771 DESULPHURIZATION OF PEAT FIRED BOILERS COST CALCULATIONS CASE: KEMl BFB-BOILER I

Emission llmit mglm3n 360 280

Prices Limestone price FiMlt 270 270 Cost of thermal power loss FIWMWh 40 40 Cost of ash diswsal FlMA 40 40

Emissions (1Ph autoabsorption) SO2 emission without desulphurization t/a 1215 1215 SO2 emission with desulphurization t/a 933 733 Removed SO2 amount t/a 282 482-

Utility consumption I I Ca/S molar ratio Imoi/moi I 3 7 Limestone t/h 1.37 3.20 Boiler power loss kW 21 9 1 292

~ t/hI~____ 0.97 2.21

Utility costs - Limestone kFIM/a 1850 4320 Boiler power loss kFIWa 44 258 Ash disposal kFIM/a 194 442 Total kFlWa 2088 5020

I I ITOTALANNUAL COSTS I I Investment kFlMla 247 494 Maintenance kFIM/a 45 90 Utiiiiity kFiM/a 2088 5020 Total kFlWa 2380 5605 t 1 Investment FIMASO2 876 1 025 Maintenance FIMAS02 160 187 Utilirii FIM/tSO2 7403 10416 Total FIMltSO2 8438 11 620 APPENDIX 7/1

DESULPHURIZATION OF PEAT FIRED BOILERS1

COST~ CALCULATIONS I I CASE: CFB-BOILER, 100 Mw,S-content 0.2%

IEmission limit lmnlMJ I 360 I 260 I 200 I

Basic data Investment kFlM I 000 2 000 2 000 Boiler power MWf 97 97 97 Annual Deak oDeratina time h 5 000 5000 5 000 Rate % 7 7 7 Period a 15 15 15 Maintenance cost (2% of investment) kFlMla 20 40 40

Prices Limestone price FIM/t 270 270 270 Cost of thermal power loss FIM/MWh 40 40 40 Cost of ash disposal FlMA 40 40 40

SO2 emission without desulDhurization Itla 388 I 388 1 388 SO2 emission with desulphurization tla 304 219 169 Removed SO2 amount Va 84 169 219

Utility consumption Ca/S molar ratio Imol/mol I 2.5 1 61 10 Limestone tlh 0.33 0.792 1.32 Boiler power loss kW 54 260 456 Ash disoosal tlh 0.25 0.52 0.78

Utility costs Limestone kFIMla 446 1 069 1 782 Boiler power loss kFlMla 11 52 91 Ash disposal kFIM/a 50 104 156 Total kFlMIa 506 1 225 2 029

TOTAL ANNUAL COSTS Investment kFIM/a 110 220 220 Maintenance kFIM/a 20 40 40 Utilility kFIM/a 506 1 225 2 029 Total kFlWa 636 1485 2 289

I I I I Investment IFIM/tS02 I 1 3021 1 3021 1001 Maintenance FIMAS02 237 237 182 Utilility FlMASO2 6 003 7 263 9 253 Total FlMltSO2 7 541 8802 I0437 DESULPHURlZATlON OF PEAT FIRED BOILERS COST CALCULATIONS CASE: CFB-BOILER. 300 MW. S-content 0.2%

Emission limit ImslMJ I 360 1 260 I 200

Prices Limestone price FlMA 270 270 270 Cost of thermal Dower loss FIM/MWh 40 40 40 ICost of ash disDosal IFlMlt 1 40 1 40 I 401 IEmissions I I I I I SO2 emission without desulphurization ffa 1188 1188 1188 SO2 emission with desulphurization ffa 930 67 1 517 Removed SO2 amount ffa 258 517 67 1

IUtility consumption I I I I I Ca/S molar ratio moUmol 2.5 6 10 Limestone ffh 1 2.41 4.03 Boiler Dower loss kW 196 996 1 659 IAsh disDosal ltlh I 0.91 I 1.701 2.841

Utility costs I

Limestone~ IkFIMla 1 3 2541 5 441 I 35018 IBoiler Dower loss lkFlM/a 1 39 I 1991 332 I Ash disposal kFIM/a 182 34 1 568 Total kFlMIa I 571 3 793 6 340

TOTAL ANNUAL COSTS Investment kFlM/a 247 494 494 Maintenance kFIM/a 45 90 90 Utilility kFIM/a 1 571 3 793 6 340 Total kFlMIa i 863 4 377 6 924

Investment FIM/tS02 957 957 736 Maintenance FIMltSO2 174 174 134 Utilility FIWtS02 6 084 7 344 9 442 Total FIMItSO2 7 215 8474 10312 APPENDM 7/3

IDESULPHURIZATtON OF PEAT FIRED BOILERS1 I COST CALCULATIONS CASE: BFB-BOILER, 100 MW, S-content 0.2% I

Emission limit mglMJ 360 280

Basic data Investment kFlM 1 000 2 000 Boiler power MVW 100 100 Annual peak operating time h 5 000 5000 Rate % 7 7 Period a 15 15 Maintenance cost (2% of investment) kFIM/a 20 40

Prices Limestone price FIMlt 270 270 Cost of thermal power loss FIM/MWh 40 40 Cost of ash disDosal FIMA 40 40

Emissions SO2 emission without desulphurization t/a 388 388 SO2 emission with desulohurization t/a 304 236 IRemoved SO2 amount I t/a I 84 I 1521

Utility consumption CalS molar ratio mol/mol 3 7 Limestone ffh 0.37 0.85 Boiler power loss kW 65 387 Ash disposal t/h 0.30 0.66

I Utility costs Limestone kFIMia 500 1148 Boiler power loss kFlMla 13 77 Ash disposal kFIM/a 61 132 Total kFIM/a 573 1 357

I I I ITOTAL ANNUAL COSTS I Investment I kFIM/a 1101 220 40

Utililitv- -...... I kFlMX !Total IkFlWa I 703 1 1 6171

Investment FIMAS02 1 302 1446 Maintenance FIMASO2 237 263 Utilility FIMAS02 6 796 8 940 Total FIMItSO2 8335 I0650 IDESULPHURIZATIONOF PEAT FIRED BOILERS1 I COST CALCULATIONS CASE: BFB-BOILER. 300 MW,S-content 0.2% I

Emission limit mglMJ 360 280

Basic data Investment kFlM 2 250 4 500 Boiler power MW 300 300 Annual peak operating time h 5 000 5000 Rate % 7 7 Period a 15 15 Maintenance cost (2% of investment) kFIM/a 45 90

Prices Limestone price FlMA 270 270 Cost of thermal power loss FIM/MWh 40 40 Cost of ash disposal FIWt 40 40

Emissions SO2 emission without desulphurization t/a 1069 1069 SO2 emission with desulphurization t/a 837 65 1 Removed SO2 amount t/a 232 418

Utility consumption CalS molar ratio moUmol 3 7 Limestone t/h 1.21 2.8 Boiler power loss kW 196 1161 Ash disposal t/h 0.91 1.99

Utility costs Limestone kFIM/a 1634 3 780 Boiler power loss kFIM/a 39 232 Ash disposal kFIM/a 182 397 Total kFlM/a I 855 4 410 I I I TOTAL ANNUAL COSTS I Investment kFIM/a 247 494 Maintenance kFIM/a 45 90 Utilility kFIMla 1 855 4 410 Total kFlM/a 2 147 4 994

Investment FIM/tS02 1 063 1181 Maintenance FIM/tS02 194 215 Utilility FIM/tS02 7980 10540 Total FIWtSOP 9236 I1936