tpp task 3 technology

November, 2007

European Agency for Reconstruction

Contract nr 05KOS01/04/005

Studies to support the development of new generation capacities and related transmission – Kosovo UNMIK

Task 3.1.A

Lignite Quality Data Collection

Studies to support the development of new generation capacities and related transmission (37) Task 3.1.A, Lignite quality data collection November, 2007

European Agency for Reconstruction Pöyry-CESI-Terna-Decon

Disclaimer

While the consortium of Pöyry, CESI, TERNA and DECON considers that the information and opinions given in this work are sound, all parties must rely upon their own skill and judgement when making use of it. The consortium members do not make any representation or warranty, expressed or implied, as to the accuracy or completeness of the information contained in this report and assumes no responsibility for the accuracy or completeness of such information. The consortium members will not assume any liability to anyone for any loss or damage arising out of the provision of this report. The report contains projections that are based on assumptions that are subject to uncertainties and contingencies. Because of the subjective judgements and inherent uncertainties of projections, and because events frequently do not occur as expected, there can be no assurance that the projections contained herein will be realised and actual results may be different from projected results. Hence the projections supplied are not to be regarded as firm predictions of the future, but rather as illustrations of what might happen. Parties are advised to base their actions on awareness of the range of such projections, and to note that the range necessarily broadens in the latter years of the projections.



TABLE OF CONTENTS

1 INTRODUCTION..................................................................................................................5

2 DRILLING LOCATIONS AND SAMPLING ....................................................................6

3 LIGNITE ANALYSIS............................................................................................................9

3.1 Comments on Lignite analysis ............................................................................................12 3.2 Graphical illustrations of different analysis results ..........................................................18

4 LIGNITE ASH ANALYSIS ................................................................................................25

5 RADIOACTIVE ELEMENTS............................................................................................37

List of Tables Table 3-1 Lignite analysis results, drillings 1-4. ................................................................................10 Table 3-2 Lignite analysis results, drillings 5-8. ................................................................................11 Table 3-3 Lignite analysis results, summary......................................................................................12 Table 3-4 Composition of ash as oxides. These calculations are based on the lignite analyses found

on Table 3 – 1 and Table 3 – 2. ..................................................................................................14 Table 4-1 Ash analysis results, drillings 1-4. .....................................................................................26 Table 4-2 Ash analysis results, drillings 5-8. .....................................................................................27 Table 4-3 Ash analysis results, summary...........................................................................................28 Table 5-1 The results of the radioactive analysis. ..............................................................................37 List of Figures Figure 2-1 Drilling locations. ...............................................................................................................6 Figure 2-2 INKOS drilling rig in the Sibovc valley (Drill # 5)............................................................7 Figure 2-3 Samples from Sibovc before sending to laboratory. ..........................................................8 Figure 3-1 Melting behaviour of the ashes tested. .............................................................................13 Figure 3-2 Main components of ash (wt. % of ash). ..........................................................................15 Figure 3-3 Minor components of ash (wt. % of ash). ........................................................................15 Figure 3-4 Melting behaviour of the ashes tested. .............................................................................16 Figure 3-5 Melting behaviour of the ashes tested as a function of CaO-content. ..............................16 Figure 3-6 Content (mg/kg ash) of trace elements in the ash.............................................................17 Figure 3-7 Analysis results – moisture content in dry lignite. ...........................................................18 Figure 3-8 Analysis results – ash content in dry lignite. ....................................................................18 Figure 3-9 Analysis results – volatile matter content in dry lignite. ..................................................19 Figure 3-10 Analysis results – fixed carbon content in dry lignite. ...................................................19 Figure 3-11 Analysis results – sulphur content in dry lignite. ...........................................................20 Figure 3-12 Analysis results – carbon and hydrogen contents in dry lignite. ....................................20 Figure 3-13 Analysis results – nitrogen content in dry lignite. ..........................................................21 Figure 3-14 Analysis results – oxygen content in dry lignite. ...........................................................21 Figure 3-15 Analysis results – fluorine content in dry lignite............................................................22 Figure 3-16 Analysis results – calorific value of moist lignite. .........................................................22 Figure 3-17 Analysis results – calculated CO2 emission factor of lignite. ........................................23



Figure 3-18 Analysis results – ash fusibility temperatures, drillings 1-4...........................................23 Figure 3-19 Analysis results – ash fusibility temperatures, drillings 5-8...........................................24 Figure 4-1 Analysis results – silicon content in dry pre-ashed lignite. ..............................................29 Figure 4-2 Analysis results – calcium content in dry pre-ashed lignite. ............................................29 Figure 4-3 Analysis results – aluminium content in dry pre-ashed lignite. .......................................30 Figure 4-4 Analysis results – iron content in dry pre-ashed lignite. ..................................................30 Figure 4-5 Analysis results – potassium content in dry pre-ashed lignite. ........................................31 Figure 4-6 Analysis results – magnesium content in dry pre-ashed lignite. ......................................31 Figure 4-7 Analysis results – sodium content in dry pre-ashed lignite. .............................................32 Figure 4-8 Analysis results – titanium content in dry pre-ashed lignite. ...........................................32 Figure 4-9 Analysis results – antimony, arseni and lead contents in dry pre-ashed lignite. ..............33 Figure 4-10 Analysis results – barium and boron contents in dry pre-ashed lignite..........................33 Figure 4-11 Analysis results – cobalt, copper and chromium contents in dry pre-ashed lignite. ......34 Figure 4-12 Analysis results – beryllium, molybden and tin contents in dry pre-ashed lignite.........34 Figure 4-13 Analysis results – nickel, vanadium and zinc contents in dry pre-ashed lignite. ...........35 Figure 4-14 Analysis results – manganese content in dry pre-ashed lignite. .....................................35 Figure 4-15 Analysis results – phosphorus content in dry pre-ashed lignite. ....................................36



1 INTRODUCTION

The extensive basic sampling on the Sibovc field lignite resource in the 1970´s comprised only the general analysis of the heat value, volatiles, moisture, ash and sulphur contents. There were more than 8000 different samples analyzed giving fairly exact information on the field. The pre-feasibility study for the lignite fired power plant utilizing the Sibovc field in 2006 identified lack of information on the concentrations of harmful elements in the lignite like chlorine, mercury, heavy metals etc.. That information is vital for the boiler design as well as for the planning of the pollution control measures for the new plant. The current assignment includes the acquisition of the lignite samples and their analysis.

Instituti INKOS sh.a. was assigned to get the samples from the field and initially to analyze the samples. During the execution of the analysis work some technical problems were encountered by equipment failures. The samples were transferred to Swedish laboratory Analycen in Lindköping that is accredited laboratory according to ISO/IEC 17025.

Some spot checks were made for radioactivity by The Finnish Radiation and Nuclear Safety Authority.



2 DRILLING LOCATIONS AND SAMPLING

The drilling and sampling program included eight different drilling holes relatively eavenly distributed over the Sibovc field, 21 km2. It was agreed that three samples are taken from each drilling i.e. one some 5 meters below the top of the lignite seam, one from the middle of the seam and one 5 meters above the bottom of the seam. The drilling locations to collect samples for the lignite analyses are located as presented in the next picture. The total length of the drilling holes was 875 meters.

Figure 2-1 Drilling locations.



Figure 2-2 INKOS drilling rig in the Sibovc valley (Drill # 5).

The samples were placed into wooden boxes with depth markings for later indentified:



Figure 2-3 Samples from Sibovc before sending to laboratory.



3 LIGNITE ANALYSIS

The results of the lignite analyses are presented with tables and diagrams in the following pages.

It has to be noted that the total sulphur (organic & inorganic) has been analyzed in oxidizing atmosphere by using iron catalyst at 1400 °C.

Studies to support the development of new

generation

capacities and related transmission - K

osovo

(37) Task 3 Lignite quality data collection

N

ovember, 2007

European Agency for R

econstruction Pöyry-C

ESI-Terna-Decon

Table 3-1 Lignite analysis results, drillings 1-4.

AnalysisU

nitAccuracy

Method

TopM

iddleBottom

TopM

iddleBottom

TopM

iddleBottom

TopM

iddleBottom

Moisture

%± 2 %

ISO 589

43.643.8

38.340.8

45.433.8

42.442.2

41.146.2

43.143.3

Ash%

± 15 %IS

O 1171/ASTM

-D 5142 m

od25.2

26.537.9

31.525.8

43.344

44.340

24.830.4

39.4Ash (as received)

%± 15 %

ISO

1171/ASTM-D

5142 mod

14.214.9

23.418.6

14.128.7

25.325.6

23.613.3

17.322.3

Volatile matter

%± 5 %

CE

N/TS 15148 m

od.46.3

48.742.2

44.647.1

3936.8

37.240.7

48.546.5

42.5Volatile m

atter (as received)%

± 5 %C

EN

/TS 15148 mod.

26.127.4

26.026.4

25.725.8

21.221.5

2426.1

26.524.1

C-fix

%± 7 %

ISO

562/ASTM-D

5142 mod

28.524.8

19.923.9

27.117.7

19.218.5

19.326.7

23.118.1

C-fix (as received)

%± 7 %

ISO

562/ASTM-D

5142 mod

16.113.9

12.314.1

14.811.7

11.110.7

11.414.4

13.110.3

Sulphur S%

± 10 %SS

187177/ASTM

D 4239 C

1.381.63

2.751.1

1.252.21

2.62.23

2.332.46

2.092.28

Sulphur S (as received)%

± 10 %SS

187177/ASTM

D 4239 C

0.780.92

1.70.65

0.681.46

1.51.29

1.371.32

1.191.29

Sulphur S (inorganic)%

± 5 %G

TK3.04

4.664.67

1.583.51

3.232.94

2.463.42

5.074.8

4.69C

hlorine Cl

%± 25 %

ASTM

-D 4208

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

Chlorine C

l (as received)%

± 25 %A

STM-D

4208<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01C

arbon C%

± 2 %ASTM

D 5373

47.545.7

4042.7

46.836.1

35.135.3

38.548.4

43.838.8

Carbon C

(as received)%

± 2 %ASTM

D 5373

26.825.7

24.725.3

25.623.9

20.220.4

22.726

24.922

Hydrogen H

%± 10 %

ASTM D

53733.8

3.22.9

3.53.4

2.93

33.1

3.73.1

3H

ydrogen H (as received)

%± 10 %

ASTM D

53737.0

6.76.0

6.67

5.76.5

6.46.4

7.26.6

6.6N

itrogen N%

± 10 %ASTM

D 5373

1.30.88

0.741.1

0.870.69

0.710.69

0.740.81

0.720.73

Nitrogen N

(as received)%

± 10 %ASTM

D 5373

0.750.49

0.460.63

0.470.46

0.410.4

0.440.44

0.410.41

Oxygen O

(calc.)%

ASTM

-D 5373

20.822.1

15.720.1

21.914.8

14.614.5

15.319.8

19.915.8

Oxygen O

(as received, calc.)%

ASTM

-D 5373

50.551.3

43.748.2

52.139.8

46.145.9

45.551.7

49.647.4

Fluorine F (dry basis)m

g/kgSS 187185

6365

6183

5161

7362

4561

6133

Calorific V

alueM

J/kgSS-IS

O 1928

18.71416.943

15.27416.841

17.77013.943

13.91813.822

15.22318.746

16.34314.792

Calorific V

alue (as received)M

J/kgSS-IS

O 1928

10.5559.522

9.4249.970

9.7039.230

8.0177.989

8.96610.085

9.2998.387

Emission factor (calc.)

t/TJ CO

297.2

103.0100.0

97.3100.7

99.396.9

98.296.9

98.8102.4

100.6

Deform

ation temperature

°C± 5 %

SS-ISO 540

12301240

12101220

11901220

12401250

12401180

12101200

Hem

isphere temperature

°C± 5 %

SS-ISO 540

12401300

12301290

12001300

13001360

13101200

12201210

Flow tem

perature°C

± 5 %SS-ISO

5401260

13101250

13101200

13401330

13601320

12001230

1220

1st drill2nd drill

3rd drill4th drill


generation


osovo


N

ovember, 2007



ESI-Terna-Decon

Table 3-2 Lignite analysis results, drillings 5-8.

AnalysisU

nitAccuracy

Method

TopM

iddleB

ottom

TopM

iddleBottom

TopM

iddleBottom

TopM

iddleBottom

Moisture

%± 2 %

ISO 589

46.439.3

39.246.2

47.135.3

43.845.8

36.645.4

45.744.2

Ash%

± 15 %IS

O 1171/ASTM

-D 5142 m

od26.9

41.744.7

20.226.7

38.923

24.839.5

24.530.3

39.1Ash (as received)

%± 15 %

ISO

1171/ASTM-D

5142 mod

14.425.3

27.210.9

14.125.2

12.913.4

2513.4

16.521.8

Volatile matter

%± 5 %

CE

N/TS 15148 m

od.48.6

41.240

51.148.7

43.349.8

47.341.7

47.947.1

41.8Volatile m

atter (as received)%

± 5 %C

EN

/TS 15148 mod.

2625

24.327.5

25.828

2825.6

26.426.2

25.623.3

C-fix

%± 7 %

ISO

562/ASTM-D

5142 mod

24.517.1

15.328.7

24.617.8

27.227.9

18.827.6

22.619.1

C-fix (as received)

%± 7 %

ISO

562/ASTM-D

5142 mod

13.110.4

9.315.4

1311.5

15.315.1

11.915.1

12.310.7

Sulphur S%

± 10 %SS

187177/ASTM

D 4239 C

1.762.51

2.581.57

1.743.07

1.351.43

2.091.35

1.292.39

Sulphur S (as received)%

± 10 %SS

187177/ASTM

D 4239 C

0.941.52

1.570.84

0.921.98

0.760.77

1.330.74

0.71.33

Sulphur S (inorganic)%

± 5 %G

TK3.69

4.004.00

3.354.28

5.213.07

3.443.24

4.052.87

2.1C

hlorine Cl

%± 25 %

ASTM

-D 4208

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

Chlorine C

l (as received)%

± 25 %A

STM-D

4208<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01<0.01

<0.01C

arbon C%

± 2 %ASTM

D 5373

4536.1

34.950.7

45.739.8

48.647.8

3847.8

43.438.7

Carbon C

(as received)%

± 2 %ASTM

D 5373

24.121.9

21.227.3

24.225.7

27.325.9

24.126.1

23.621.6

Hydrogen H

%± 10 %

ASTM D

53733.3

2.72.8

3.73.1

2.83.4

3.12.8

32.7

2.7H

ydrogen H (as received)

%± 10 %

ASTM D

53736.9

6.16.1

7.26.9

5.86.8

6.85.9

6.76.6

6.5N

itrogen N%

± 10 %ASTM

D 5373

0.750.73

0.741.1

0.810.79

1.30.9

0.661.1

0.810.86

Nitrogen N

(as received)%

± 10 %ASTM

D 5373

0.40.44

0.450.61

0.430.51

0.710.49

0.420.61

0.440.48

Oxygen O

(calc.)%

ASTM

-D 5373

22.316.2

14.322.7

21.914.6

22.322

16.922.2

21.516.2

Oxygen O

(as received, calc.)%

ASTM

-D 5373

53.344.7

43.553.1

53.440.8

51.552.6

43.252.4

52.248.3

Fluorine F (dry basis)m

g/kgSS 187185

8848

5698

6353

12563

6953

3548

Calorific V

alueM

J/kgSS-IS

O 1928

16.80313.489

13.58519.544

17.28715.236

18.70718.079

14.70817.817

16.19414.809

Calorific V

alue (as received)M

J/kgSS-IS

O 1928

9.0078.188

8.26010.514

9.1459.857

10.5139.799

9.3259.728

8.7938.263

Emission factor (calc.)

t/TJ CO

2102.4

102.698.5

99.1100.8

99.799.1

100.698.7

102.1102

99.7

Deform

ation temperature

°C± 5 %

SS-ISO 540

12501200

12201250

12101210

11901230

12001270

12801210

Hem

isphere temperature

°C± 5 %

SS-ISO 540

12701220

12501310

12601230

12101240

12501300

13001240

Flow tem

perature°C

± 5 %SS-ISO

5401280

12301270

13201280

12401210

12501260

13101310

1270

5th drill6th drill

7th drill8th drill

Studies to support the development of new generation capacities and related transmission - Kosovo (37) Task 3 Lignite quality data collection November, 2007


Table 3-3 Lignite analysis results, summary.

Analysis Unit Accuracy Method Average Maximum MinimumMoisture % ± 2 % ISO 589 42.46 47.1 33.8Ash % ± 15 % ISO 1171/ASTM-D 5142 mod 33.06 44.7 20.2Ash (as received) % ± 15 % ISO 1171/ASTM-D 5142 mod 19.23 28.7 10.9Volatile matter % ± 5 % CEN/TS 15148 mod. 44.53 51.1 36.8Volatile matter (as received) % ± 5 % CEN/TS 15148 mod. 25.52 28 21.2C-fix % ± 7 % ISO 562/ASTM-D 5142 mod 22.42 28.7 15.3C-fix (as received) % ± 7 % ISO 562/ASTM-D 5142 mod 12.79 16.1 9.3Sulphur S % ± 10 % SS 187177/ASTM D 4239 C 1.98 3.07 1.1Sulphur S (as received) % ± 10 % SS 187177/ASTM D 4239 C 1.15 1.98 0.65Sulphur S (inorganic) % ± 5 % GTK 3.64 5.21 1.58Chlorine Cl % ± 25 % ASTM-D 4208 <0.01 <0.01 <0.01Chlorine Cl (as received) % ± 25 % ASTM-D 4208 <0.01 <0.01 <0.01Carbon C % ± 2 % ASTM D 5373 42.30 50.7 34.9Carbon C (as received) % ± 2 % ASTM D 5373 24.22 27.3 20.2Hydrogen H % ± 10 % ASTM D 5373 3.11 3.8 2.7Hydrogen H (as received) % ± 10 % ASTM D 5373 6.54 7.2 5.7Nitrogen N % ± 10 % ASTM D 5373 0.86 1.3 0.66Nitrogen N (as received) % ± 10 % ASTM D 5373 0.49 0.75 0.4Oxygen O (calc.) % ASTM-D 5373 18.68 22.7 14.3Oxygen O (as received, calc.) % ASTM-D 5373 48.37 53.4 39.8

Fluorine F (dry basis) mg/kg SS 187185 63.25 125 33

Calorific Value MJ/kg SS-ISO 1928 16.19 19.544 13.489Calorific Value (as received) MJ/kg SS-ISO 1928 9.27 10.555 7.989

Emission factor (calc.) t/TJ CO2 99.86 103 96.9

Deformation temperature °C ± 5 % SS-ISO 540 1223 1280 1180Hemisphere temperature °C ± 5 % SS-ISO 540 1260 1360 1200Flow temperature °C ± 5 % SS-ISO 540 1273 1360 1200

Summary analysis

3.1 Comments on Lignite analysis

The analysis of lignite carried out by AnalyCen in May-June 2007 reveals an extremely low chlorine content. Thus there will be no risks for chlorine induced corrosion in any boiler where this lignite will be combusted. However, the behaviour of the ash of this lignite can become a problematic one. According to these analyses the melting behaviour of these ashes shows narrow windows for melting and freezing points. The temperature difference between deformation and flow temperatures of the 4th drill, 5th drill and 7th drill is only 30 oC or less, Figure 1. Otherwise, the ash of this lignite has a typical composition for lignite coal ashes. It basically consists of 40 % of silica (SiO2), of 20 % of alumina (Al2O3), of 25 % of calcium (CaO) and 10 % of iron oxide. This iron oxide can be either wustite (FeO) or hematite (Fe2O3) depending on the oxide content of the smelt. In reducing atmospheres the iron of this lignite may turn to fayalite (iron silicate) which transforms this ash to a low melting and very easily flowing smelt. Thus, in practice this kind of ash is normally handled with calcium additions. Calcium may be needed



for the sulphur removal so that it is a natural addition component. There will be an optimum calcium addition when heavy metal behaviour in the boiler is in focus. The content of potassium is around 1 %, which should not originate any bigger problems with any kind of boiler chosen for the combustion of this lignite.

Deformation, Hemisphere and Flow Temperatures

1050

1100

1150

1200

1250

1300

1350

14001s

t dril

l

2nd

drill

3rd

drill

4th

drill

5th

drill

6th

drill

7th

drill

8th

drill

Tem

pera

ture

in o

C

Deformation temperature °CHemisphere temperature °CFlow temperature °C

Figure 3-1 Melting behaviour of the ashes tested.

Additional comments added in November 2007:

The analysis of lignite carried out by AnalCen in May-June 2007 reveals an extremely low chlorine content. Thus there will be no risks for chlorine induced corrosion in any boiler where this lignite will be combusted. When the main components of this ash transform to oxides during combustion ash composition will vary as presented in table 3-4.



Table 3-4 Composition of ash as oxides. These calculations are based on the lignite analyses found on Table 3 – 1 and Table 3 – 2.

1_Top 1_Middle 1_Bottom 2_Top 2_Middle 2_Bottom 3_Top 3_Middle 3_Bottom 4_Top 4_Middle 4_Bottom

SiO2 46.74 28.73 44.46 51.93 37.19 49.29 67.76 48.38 50.25 44.89 43.17 42.04CaO 17.53 49.73 20.84 13.29 37.19 12.51 9.49 10.11 12.01 29.46 37.17 25.69 Al2O3 18.99 6.08 16.67 21.74 10.72 22.75 3.16 26.88 23.29 12.48 6.60 16.35Fe2O3 7.30 7.74 11.67 6.04 7.00 9.61 12.95 10.00 9.31 7.57 8.03 9.58K2O 1.31 0.36 0.83 1.57 0.57 1.39 2.56 1.40 1.23 0.73 0.35 1.28MgO 6.13 5.53 3.75 3.38 5.25 2.91 2.41 1.94 2.70 3.51 3.60 3.50MnO2 0.06 0.44 0.15 0.57 0.30 0.12 0.18 0.20 0.05 0.24 0.36 0.25Na2O 0.80 0.67 0.60 0.54 0.97 0.64 0.35 0.20 0.32 0.28 0.19 0.26P2O5 0.18 0.33 0.18 0.13 0.30 0.12 0.15 0.10 0.13 0.25 0.26 0.29TiO2 0.70 0.22 0.58 0.76 0.49 0.61 0.93 0.75 0.65 0.42 0.22 0.68

1st drill 2nd drill 3rd drill 4th drill

5_Top 5_Middle 5_Bottom 6_Top 6_Middle 6_Bottom 7_Top 7_Middle 7_Bottom 8_Top 8_Middle 8_Bottom Average34.91 45.39 45.11 29.13 47.98 40.54 34.79 39.35 41.55 29.83 31.69 36.58 41.24 SiO2

45.65 22.69 17.84 41.13 59.98 21.46 30.44 38.12 24.32 47.94 40.94 26.83 22.61 CaO7.65 16.39 19.93 12.68 10.11 19.08 17.40 9.10 19.26 11.72 12.41 19.51 19.29 Al2O3

5.77 9.96 11.54 7.88 10.97 13.12 7.39 7.01 9.32 5.43 8.06 11.46 9.58 Fe2O3

0.39 1.02 1.05 0.65 0.51 0.99 1.00 0.44 0.83 0.53 0.66 0.98 1.13 K2O4.30 3.53 2.94 6.85 6.85 3.22 6.81 4.06 3.04 3.20 4.89 3.29 4.59 MgO0.40 0.19 0.10 0.24 0.57 0.16 0.14 0.33 0.12 0.34 0.22 0.13 0.10 MnO2

0.35 0.50 0.49 0.65 0.86 0.54 1.10 1.01 0.77 0.34 0.55 0.66 0.72 Na2O0.26 0.21 0.15 0.27 0.43 0.18 0.22 0.21 0.13 0.29 0.25 0.15 0.16 P2O5

0.30 0.54 0.77 0.46 0.34 0.66 0.65 0.34 0.59 0.35 0.29 0.37 0.52 TiO2

5th drill 6th drill 7th drill 8th drill

These compositions are seen in graphic forms in Figure 3-2 and Figure 3-3.

Ash of this lignite has a typical composition for lignite coal ashes. In average it consists of 41 % of silica (SiO2), of 19 % of alumina (Al2O3), 9.6 % of iron oxide (Fe2O3) and 4.6 % of magnesia (MgO). The total content of potassium and sodium oxides is close to 2 %, which is rather typical. Also the contents of phosphorus oxide (P2O5) and of titania (TiO2) are almost negligible.



Ash Composition (Wt.%)

05

10152025303540455055606570

SiO2 CaO Al2O3 Fe2O3 K2O MgO MnO2 Na2O P2O5 TiO2

1_Top1_Middle1_Bottom2_Top2_Middle2_Bottom3_Top3_Middle3_Bottom4_Top4_Middle4_Bottom 5_Top5_Middle5_Bottom 6_Top6_Middle6_Bottom7_Top7_Middle7_Bottom8_Top8_Middle8_BottomAverage

Figure 3-2 Main components of ash (wt. % of ash).

Minor ash components (Wt %)

0.000.200.400.600.801.001.201.401.601.802.002.202.402.602.80

K2O MnO2 Na2O P2O5 TiO2


Figure 3-3 Minor components of ash (wt. % of ash).

However, the behaviour of the ash of this lignite can become a problematic one. According to these analyses the melting behaviour of these ashes shows narrow windows for melting and solidification points. The temperature difference between deformation and flow temperature of the drill 4th drill, 5th drill and 7th drill is only 30oC or less, Figure 3-4.



Deformation, Hemisphere and Flow Temperatures

1050

1100

1150

1200

1250

1300

1350

1400

1st d

rill

2nd

drill

3rd

drill

4th

drill

5th

drill

6th

drill

7th

drill

8th

drill

Tem

pera

ture

in o

C

Deformation temperature °CHemisphere temperature °CFlow temperature °C

Figure 3-4 Melting behaviour of the ashes tested.

The melting behaviour of this ash is dependent on the calcia (i.e. CaO) content of the ash, Figure 3-5. Calcia in the ash will act as a sulphur remover and thus, its content as Ca-Al-silicate actually will be lower than calculated here. In practice it is most obvious that some calcia will be needed for the control of ash behaviour in the boiler. Also the form of iron oxide is critical for the ash behaviour.

Melting behaviour of Ash

1000

1050

1100

1150

1200

1250

1300

1350

1400

0 10 20 30 40 50 60 70CaO-content in the Ash

Tem

pera

ture

in d

eg. C

Deformation t.Hemisph.t.Flow t.

Figure 3-5 Melting behaviour of the ashes tested as a function of CaO-content.

The variation of trace elements in the ash is seen in Figure 3-6. The leachability of heavy metals is strongly dependent on the CaO-content of the ash.



Trace elements in Ash (mg/kg)

0

100

200

300

400

500

600

Sb As Pb Ba Be B Cd Co Cu Hg Cr Mo Ni V Sn Zn


Figure 3-6 Content (mg/kg ash) of trace elements in the ash.

The content of nickel, which is of high value today in the metal market, is high in this lignite. The value of nickel in one ton of this ash according to the LME price today in average exceeds 4000 euros.



3.2 Graphical illustrations of different analysis results

Sibovc Sampling 2007Moisture Content in Dry Lignite

0

5

10

15

20

25

30

35

40

45

50

1T 1M 1B 2T 2M 2B 3T 3M 3B 4T 4M 4B 5T 5M 5B 6T 6M 6B 7T 7M 7B 8T 8M 8B

DrillingsTop/Middle/Bottom

Perc

enta

ge %

Figure 3-7 Analysis results – moisture content in dry lignite.

Sibovc Sampling 2007Ash Content in Dry Lignite

0

5

10

15

20

25

30

35

40

45

50



Perc

enta

ge %

Figure 3-8 Analysis results – ash content in dry lignite.



Sibovc Sampling 2007Volatile Matter in Dry Lignite

0

10

20

30

40

50

60



Perc

enta

ge %

Figure 3-9 Analysis results – volatile matter content in dry lignite.

Sibovc Sampling 2007 Fixed Carbon in Dry Lignite

0

5

10

15

20

25

30

35


Drillings Top/Middle/Bottom

Perc

enta

ge %

Figure 3-10 Analysis results – fixed carbon content in dry lignite.



Sibovc Sampling 2007 Sulphur Content in Dry Lignite

0.0

1.0

2.0

3.0

4.0

5.0

6.0



Perc

enta

ge %

Organic SulphurInorganic Sulphur

Figure 3-11 Analysis results – sulphur content in dry lignite.

Sibovc Sampling 2007 Carbon and Hydrogen Contents in Dry Lignite

0

10

20

30

40

50

60



Perc

enta

ge %

Carbon CHydrogen H

Figure 3-12 Analysis results – carbon and hydrogen contents in dry lignite.



Sibovc Sampling 2007 Nitrogen Content in Dry Lignite

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4



Perc

enta

ge %

Figure 3-13 Analysis results – nitrogen content in dry lignite.

Sibovc Sampling 2007 Oxygen Content in Dry Lignite

0

5

10

15

20

25



Perc

enta

ge %

Figure 3-14 Analysis results – oxygen content in dry lignite.



Sibovc Sampling 2007 Fluorine Content in Dry Lignite

0

20

40

60

80

100

120

140



Con

tent

mg/

kg

Figure 3-15 Analysis results – fluorine content in dry lignite.

Sibovc Sampling 2007 Calorific Value of Lignite (as received)

0

2

4

6

8

10

12



HH

V M

J/kg

Figure 3-16 Analysis results – calorific value of moist lignite.



Sibovc Sampling 2007 CO2 Emission Factor

93

94

95

96

97

98

99

100

101

102

103

104

1T 1M 1B 2T 2M 2B 3T 3M 3B 4T 4M 4B 5T 5M 5B 6T 6M 6B 7T 7M 7B 8T 8M 8BDrillings

Top/Middle/Bottom

ton/

TJ C

O2

Figure 3-17 Analysis results – calculated CO2 emission factor of lignite.

Sibovc Sampling 2007 Ash Fusibility

11601170118011901200121012201230124012501260127012801290130013101320

1T 1M 1B

Drilling OneTop/Middle/Bottom

Deg

rees

°C Deformation temperatureHemisphere temperatureFlow temperature


1100

1150

1200

1250

1300

1350

1400

2T 2M 2B

Drilling TwoTop/Middle/Bottom

Deg

rees



1180

1200

1220

1240

1260

1280

1300

1320

1340

1360

1380

3T 3M 3B

Drilling ThreeTop/Middle/Bottom

Deg

rees



1150

1160

1170

1180

1190

1200

1210

1220

1230

1240

4T 4M 4B

Drilling FourTop/Middle/Bottom

Deg

rees


Figure 3-18 Analysis results – ash fusibility temperatures, drillings 1-4.




1160

1180

1200

1220

1240

1260

1280

1300

5T 5M 5B

Drilling Five Top/Middle/Bottom

Deg

rees



1140

1160

1180

1200

1220

1240

1260

1280

1300

1320

1340

6T 6M 6B

Drilling Six Top/Middle/Bottom

Deg

rees



1140

1160

1180

1200

1220

1240

1260

1280

7T 7M 7B

Drilling SevenTop/Middle/Bottom

Degr

ees



1160

1180

1200

1220

1240

1260

1280

1300

1320

8T 8M 8B

Drilling Eight Top/Middle/bottom

Deg

rees


Figure 3-19 Analysis results – ash fusibility temperatures, drillings 5-8.



4 LIGNITE ASH ANALYSIS

The lignite samples were burnt (at 800 °C) after performing lignite analyses to specify the ash characteristics. The results of these pre-ashed sample analyses are presented with tables and diagrams in the next pages.


generation


osovo


N

ovember, 2007



ESI-Terna-Decon

Table 4-1 Ash analysis results, drillings 1-4.

AnalysisU

nitAccuracy

Method

TopM

iddleBottom

TopM

iddleBottom

TopM

iddleBottom

TopM

iddleB

ottom

Silicon Si

mg/kg

± 20 %EN

13656 mod.

150 000120 000

150 000200 000

160 000180 000

210 000210 000

190 000150 000

170 000170000

Siliconoxide S

iO2

mg/kg

± 20 %EN

13656 mod.

320 000260 000

320 000430 000

340 000390 000

450 000450 000

410 000320 000

360 000360000

Calcium

Ca

mg/kg

± 30 %EN

13656 mod.

87 000320 000

110 00077 000

240 00071 000

45 00067 000

70 000150 000

220 000160000

Calcium

oxide CaO

mg/kg

± 30 %EN

13656 mod.

120 000450 000

150 000110 000

340 00099 000

63 00094 000

98 000210 000

310 000220000

Alum

inium A

lm

g/kg± 25 %

EN 13656 m

od.71 000

29 00066 000

93 00052 000

94 00011 000

130 000100 000

47 00029 000

74000A

luminium

oxide Al2 O3

mg/kg

± 25 %EN

13656 mod.

130 00055 000

120 000180 000

98 000180 000

21 000250 000

190 00089 000

55 000140000

Iron Fem

g/kg± 25 %

EN 13656 m

od.35 000

49 00059 000

35 00045 000

53 00060 000

65 00053 000

38 00047 000

57000Ironoxide Fe

2 O3

mg/kg

± 25 %EN

13656 mod.

50 00070 000

84 00050 000

64 00076 000

86 00093 000

76 00054 000

67 00082000

Potassium

Km

g/kg± 20 %

EN 13656 m

od.7 400

2 7005 000

11 0004 300

9 50014 000

11 0008 600

4 3002 400

9100P

otassiumoxide K

2 Om

g/kg± 20 %

EN 13656 m

od.9 000

3 3006 000

13 0005 200

11 00017 000

13 00010 000

5 2002 900

11000M

agnesium M

gm

g/kg± 20 %

EN 13656 m

od.25 000

30 00016 000

17 00029 000

14 0009 300

11 00013 000

15 00018 000

18000M

agnesiumoxide M

gOm

g/kg± 20 %

EN 13656 m

od.42 000

50 00027 000

28 00048 000

23 00016 000

18 00022 000

25 00030 000

30000M

anganese Mn

mg/kg

± 20 %EN

13656 mod.

2702 500

6703 000

1 700600

7601 200

2801 100

1 9001300

Manganeseoxide M

nO2

mg/kg

± 20 %EN

13656 mod.

4304 000

1 1004 700

2 700950

1 2001 900

4401 700

3 0002100

Sodium

Na

mg/kg

± 20 %EN

13656 mod.

4 1004 500

3 2003 300

6 6003 800

1 7001 400

1 9001 500

1 2001600

Sodium

oxide Na

2 Om

g/kg± 20 %

EN 13656 m

od.5 500

6 1004 300

4 5008 900

5 1002 300

1 9002 600

2 0001 600

2200P

hosphorus Pm

g/kg± 20 %

EN 13656 m

od.540

1 300560

5001 200

400440

420490

790950

1100P

hosphorusoxide P2 O

5m

g/kg± 20 %

EN 13656 m

od.1 200

3 0001 300

1 1002 700

9201 000

9601 100

1 8002 200

2500Titanium

Tim

g/kg± 20 %

EN 13656 m

od.2 900

1 2002 500

3 8002 700

2 9003 700

4 2003 200

1 8001 100

3500Titanium

oxide TiO2

mg/kg

± 20 %EN

13656 mod.

4 8002 000

4 2006 300

4 5004 800

6 2007 000

5 3003 000

1 8005800

Antim

ony Sbm

g/kg± 25 %

EN 13656 m

od.2.8

<2.54.7

3.52.7

3.53.1

3.84.1

33.3

3.3A

rsenic As

mg/kg

± 15 %EN

13656 mod.

3348

6622

4243

3641

8138

4447

Lead Pbm

g/kg± 20 %

EN 13656 m

od.23

825

3113

3541

5340

149.9

14B

arium Ba

mg/kg

± 20 %EN

13656 mod.

440550

450510

800570

460660

610830

2701000

Beryllium

Bem

g/kg± 25 %

EN 13656 m

od.<2.5

<2.5<2.5

2.8<2.5

<2.52.9

33.1

<2.5<2.5

<2.5B

oron Bm

g/kg± 20 %

SS028150-2450

570450

69180

11076

100120

320280

220C

admium

Cd

mg/kg

± 30 %EN

13656 mod.

<0.50<0.50

<0.50<0.50

<0.50<0.50

<0.50<0.50

<0.50<0.50

<0.500.56

Cobalt C

om

g/kg± 30 %

EN 13656 m

od.18

1417

1213

1413

1219

1422

24C

opper Cu

mg/kg

± 20 %EN

13656 mod.

5329

7448

3452

6367

6644

3779

Mercury H

gm

g/kg± 25 %

SS028150-2<0.045

<0.045<0.045

<0.045<0.045

<0.045<0.045

<0.045<0.045

<0.0450.092

<0.045C

hromium

Cr

mg/kg

± 30 %EN

13656 mod.

15063

190170

87170

160190

180110

100210

Molybden M

om

g/kg± 25 %

EN 13656 m

od.14

<1022

2421

1128

<10<10

24<10

28N

ickel Ni

mg/kg

± 30 %EN

13656 mod.

240130

330170

120150

160150

210170

290470

Vanadium

Vm

g/kg± 25 %

EN 13656 m

od.140

42110

17059

120140

140150

7552

110Tin Sn

mg/kg

± 20 %EN

13656 mod.

2.7<2.5

2.73.6

<2.53.3

3.54.2

3.6<2.5

<2.5<2.5

Zinc Znm

g/kg± 25 %

EN 13656 m

od.110

<2549

62<25

80100

11088

29<25

70

1st drill2nd drill

3rd drill4th drill


generation


osovo


N

ovember, 2007



ESI-Terna-Decon

Table 4-2 Ash analysis results, drillings 5-8.

AnalysisU

nitAccuracy

Method

TopM

iddleBottom

Top

Middle

BottomTop

Middle

BottomTop

Middle

Bottom

Silicon Si

mg/kg

± 20 %EN

13656 mod.

120 000170 000

20000081 000

130 000160 000

110 000150 000

190 000130 000

110 000140 000

Siliconoxide S

iO2

mg/kg

± 20 %EN

13656 mod.

260 000360 000

430000170 000

280 000340 000

240 000320 000

410 000280 000

240 000300 000

Calcium

Ca

mg/kg

± 30 %EN

13656 mod.

240 000130 000

120000170 000

250 000130 000

150 000220 000

170 000320 000

220 000160 000

Calcium

oxide CaO

mg/kg

± 30 %EN

13656 mod.

340 000180 000

170000240 000

350 000180 000

210 000310 000

240 000450 000

310 000220 000

Alum

inium A

lm

g/kg± 25 %

EN 13656 m

od.30 000

70 000100000

39 00031 000

83 00061 000

39 00099 000

56 00050 000

84 000A

luminium

oxide Al2 O3

mg/kg

± 25 %EN

13656 mod.

57 000130 000

19000074 000

59 000160 000

120 00074 000

190 000110 000

94 000160 000

Iron Fem

g/kg± 25 %

EN 13656 m

od.30 000

55 00074000

32 00045 000

78 00036 000

40 00064 000

36 00043 000

66 000Ironoxide Fe

2 O3

mg/kg

± 25 %EN

13656 mod.

43 00079 000

11000046 000

64 000110 000

51 00057 000

92 00051 000

61 00094 000

Potassium

Km

g/kg± 20 %

EN 13656 m

od.2 400

6 7008400

3 1002 500

6 9005 700

3 0006 800

4 1004 100

6 600P

otassiumoxide K

2 Om

g/kg± 20 %

EN 13656 m

od.2 900

8 10010000

3 8003 000

8 3006 900

3 6008 200

5 0005 000

8 000M

agnesium M

gm

g/kg± 20 %

EN 13656 m

od.19 000

17 00017000

24 00024 000

16 00028 000

20 00018 000

18 00022 000

16 000M

agnesiumoxide M

gOm

g/kg± 20 %

EN 13656 m

od.32 000

28 00028000

40 00040 000

27 00047 000

33 00030 000

30 00037 000

27 000M

anganese Mn

mg/kg

± 20 %EN

13656 mod.

1 900940

600900

2 100840

6501 700

7502 000

1 100710

Manganeseoxide M

nO2

mg/kg

± 20 %EN

13656 mod.

3 0001 500

9501 400

3 3001 300

1 0002 700

1 2003 200

1 7001 100

Sodium

Na

mg/kg

± 20 %EN

13656 mod.

1 9003 000

35002 800

3 7003 300

5 6006 100

5 6002 400

3 1004 000

Sodium

oxide Na

2 Om

g/kg± 20 %

EN 13656 m

od.2 600

4 0004700

3 8005 000

4 5007 600

8 2007 600

3 2004 200

5 400P

hosphorus Pm

g/kg± 20 %

EN 13656 m

od.830

730630

6801 100

670670

760570

1 200830

530P

hosphorusoxide P2 O

5m

g/kg± 20 %

EN 13656 m

od.1 900

1 7001400

1 6002 500

1 5001 500

1 7001 300

2 7001 900

1 200Titanium

Tim

g/kg± 20 %

EN 13656 m

od.1 300

2 6004400

1 6001 200

3 3002 700

1 7003 500

2 0001 300

1 800Titanium

oxide TiO2

mg/kg

± 20 %EN

13656 mod.

2 2004 300

73002 700

2 0005 500

4 5002 800

5 8003 300

2 2003 000

Antim

ony Sbm

g/kg± 25 %

EN 13656 m

od.<2.5

3.83.9

<2.53.3

52.6

<2.54.9

2.5<2.5

3.8A

rsenic As

mg/kg

± 15 %EN

13656 mod.

3043

6320

6067

2434

6037

4262

Lead Pbm

g/kg± 20 %

EN 13656 m

od.8.6

2220

9.68.9

2216

9.628

1418

32B

arium Ba

mg/kg

± 20 %EN

13656 mod.

450370

470400

490390

450440

550680

740630

Beryllium

Bem

g/kg± 25 %

EN 13656 m

od.<2.5

<2.5<2.5

<2.5<2.5

<2.5<2.5

<2.53.2

<2.5<2.5

3B

oron Bm

g/kg± 20 %

SS028150-2270

240240

220280

300500

520360

170120

160C

admium

Cd

mg/kg

± 30 %EN

13656 mod.

<0.50<0.50

0.56<0.50

<0.50<0.50

<0.50<0.50

<0.50<0.50

<0.50<0.50

Cobalt C

om

g/kg± 30 %

EN 13656 m

od.11

2224

8.320

189.7

1114

1311

13C

opper Cu

mg/kg

± 20 %EN

13656 mod.

2571

9234

4076

3917

7929

3050

Mercury H

gm

g/kg± 25 %

SS028150-2<0.045

<0.045<0.045

<0.045<0.045

<0.045<0.045

<0.045<0.045

<0.045<0.045

<0.045C

hromium

Cr

mg/kg

± 30 %EN

13656 mod.

100180

220100

110190

9366

230100

94150

Molybden M

om

g/kg± 25 %

EN 13656 m

od.34

<1014

20<10

<1012

<10<10

<10<10

<10N

ickel Ni

mg/kg

± 30 %EN

13656 mod.

130350

480140

280340

15090

32097

150160

Vanadium

Vm

g/kg± 25 %

EN 13656 m

od.42

110130

5967

11076

45180

7166

120Tin Sn

mg/kg

± 20 %EN

13656 mod.

<2.52.5

2.6<2.5

<2.52.6

<2.5<2.5

3<2.5

<2.53

Zinc Znm

g/kg± 25 %

EN 13656 m

od.<25

51100

<25<25

5040

<2559

2930

57

5th drill6th drill

7th drill8th drill



Table 4-3 Ash analysis results, summary.

Analysis Unit Accuracy Method Average Maximum MinimumSilicon Si mg/kg ± 20 % EN 13656 mod. 145 000 210 000 81 000Siliconoxide SiO2 mg/kg ± 20 % EN 13656 mod. 310 000 450 000 170 000Calcium Ca mg/kg ± 30 % EN 13656 mod. 123 500 320 000 45 000Calciumoxide CaO mg/kg ± 30 % EN 13656 mod. 170 000 450 000 63 000Aluminium Al mg/kg ± 25 % EN 13656 mod. 77 500 130 000 11 000Aluminiumoxide Al2O3 mg/kg ± 25 % EN 13656 mod. 145 000 250 000 21 000Iron Fe mg/kg ± 25 % EN 13656 mod. 50 500 78 000 30 000Ironoxide Fe2O3 mg/kg ± 25 % EN 13656 mod. 72 000 110 000 43 000Potassium K mg/kg ± 20 % EN 13656 mod. 7 000 14 000 2 400Potassiumoxide K2O mg/kg ± 20 % EN 13656 mod. 8 500 17 000 2 900Magnesium Mg mg/kg ± 20 % EN 13656 mod. 20 500 30 000 9 300Magnesiumoxide MgO mg/kg ± 20 % EN 13656 mod. 34 500 50 000 16 000Manganese Mn mg/kg ± 20 % EN 13656 mod. 490 3 000 270Manganeseoxide MnO2 mg/kg ± 20 % EN 13656 mod. 765 4 700 430Sodium Na mg/kg ± 20 % EN 13656 mod. 4 050 6 600 1 200Sodiumoxide Na2O mg/kg ± 20 % EN 13656 mod. 5 450 8 900 1 600Phosphorus P mg/kg ± 20 % EN 13656 mod. 535 1 300 400Phosphorusoxide P2O5 mg/kg ± 20 % EN 13656 mod. 1 200 3 000 920Titanium Ti mg/kg ± 20 % EN 13656 mod. 2 350 4 400 1 100Titaniumoxide TiO2 mg/kg ± 20 % EN 13656 mod. 3 900 7 300 1 800Antimony Sb mg/kg ± 25 % EN 13656 mod. 3 5 3Arsenic As mg/kg ± 15 % EN 13656 mod. 48 81 20Lead Pb mg/kg ± 20 % EN 13656 mod. 28 53 8Barium Ba mg/kg ± 20 % EN 13656 mod. 535 1 000 270Beryllium Be mg/kg ± 25 % EN 13656 mod. 3 3 3Boron B mg/kg ± 20 % SS028150-2 305 570 69Cadmium Cd mg/kg ± 30 % EN 13656 mod. <0.50 0 0Cobalt Co mg/kg ± 30 % EN 13656 mod. 16 24 8Copper Cu mg/kg ± 20 % EN 13656 mod. 52 92 17Mercury Hg mg/kg ± 25 % SS028150-2 <0.045 0 0Chromium Cr mg/kg ± 30 % EN 13656 mod. 150 230 63Molybden Mo mg/kg ± 25 % EN 13656 mod. 14 34 11Nickel Ni mg/kg ± 30 % EN 13656 mod. 200 480 90Vanadium V mg/kg ± 25 % EN 13656 mod. 130 180 42Tin Sn mg/kg ± 20 % EN 13656 mod. 3 4 3Zinc Zn mg/kg ± 25 % EN 13656 mod. 84 110 29

Analysis summary



Sibovc Sampling 2007 Silicon in Dry Ash

0

50 000

100 000

150 000

200 000

250 000

300 000

350 000

400 000

450 000

500 000


Top/Middle/Bottom

mg/

kg

Silicon SiSiliconoxide SiO2

Figure 4-1 Analysis results – silicon content in dry pre-ashed lignite.

Sibovc Sampling 2007 Calcium in Dry Ash

0

50 000

100 000

150 000

200 000

250 000

300 000

350 000

400 000

450 000

500 000


Top/Middle/Bottom

mg/

kg

Calcium CaCalciumoxide CaO

Figure 4-2 Analysis results – calcium content in dry pre-ashed lignite.

Studies to support the development of new November, 2007 generation capacities and related transmission (37) Task 3.1.B – Ash utilization


Sibovc Sampling 2007 Aluminium in Dry Ash

0

50 000

100 000

150 000

200 000

250 000

300 000



mg/

kgAluminium AlAluminiumoxide Al2O3

Figure 4-3 Analysis results – aluminium content in dry pre-ashed lignite.

Sibovc Sampling 2007 Iron in Dry Ash

0

20 000

40 000

60 000

80 000

100 000

120 000


Top/Middle/Bottom

mg/

kg

Iron FeIronoxide Fe2O3

Figure 4-4 Analysis results – iron content in dry pre-ashed lignite.



Sibovc Sampling 2007 Potassium in Dry Ash

0

2 000

4 000

6 000

8 000

10 000

12 000

14 000

16 000

18 000

1T 1M 1B 2T 2M 2B 3T 3M 3B 4T 4M 4B 5T 5M 5B 6T 6M 6B 7T 7M 7B 8T 8M 8BDrilllings

Top/Middle/Bottom

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Potassium KPotassiumoxide K2O

Figure 4-5 Analysis results – potassium content in dry pre-ashed lignite.

Sibovc Sampling 2007 Magnesium in Dry Ash

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Magnesium MgMagnesiumoxide MgO

Figure 4-6 Analysis results – magnesium content in dry pre-ashed lignite.



Sibovc Sampling 2007 Sodium in Dry Ash

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Sodium NaSodiumoxide Na2O

Figure 4-7 Analysis results – sodium content in dry pre-ashed lignite.

Sibovc Sampling 2007 Titanium in Dry Ash

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Titanium TiTitaniumoxide TiO2

Figure 4-8 Analysis results – titanium content in dry pre-ashed lignite.



Sibovc Sampling 2007 Antimony, Arsenic and Lead in Dry Ash

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Antimony SbArsenic AsLead Pb

Figure 4-9 Analysis results – antimony, arseni and lead contents in dry pre-ashed lignite.

Sibovc Sampling 2007 Barium and Boron in Dry Ash

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Barium BaBoron B

Figure 4-10 Analysis results – barium and boron contents in dry pre-ashed lignite.



Sibovc Sampling 2007 Cobalt, Copper and Chromium in Dry Ash

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Cobalt CoCopper CuChromium Cr

Figure 4-11 Analysis results – cobalt, copper and chromium contents in dry pre-ashed lignite.

Sibovc Sampling 2007 Beryllium, Molybden and Tin in Dry Ash

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Beryllium BeMolybden MoTin Sn

Figure 4-12 Analysis results – beryllium, molybden and tin contents in dry pre-ashed lignite.



Sibovc Sampling 2007 Nickel Vanadium and Zinc in Dry Ash

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Nickel NiVanadium VZinc Zn

Figure 4-13 Analysis results – nickel, vanadium and zinc contents in dry pre-ashed lignite.

Sibovc Sampling 2007 Manganese in Dry Ash

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Manganese MnManganeseoxide MnO2

Figure 4-14 Analysis results – manganese content in dry pre-ashed lignite.



Sibovc Sampling 2007 Phophorus in Dry Ash

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Phosphorus PPhosphorusoxide P2O5

Figure 4-15 Analysis results – phosphorus content in dry pre-ashed lignite.



5 RADIOACTIVE ELEMENTS

Five different samples were taken for radioactive analysis at the Finnish Radiation and Nuclear Safety Institute and the results are: Table 5-1 The results of the radioactive analysis.

Sampling location Item Result + tolerance Ref. date

The reference date is for which the radiation result has been calculated Basically the radiation levels are normal – no special measures required in this respect.

November, 2007




Task 3.1.B

Report on Ash Utilization

Studies to support the development of new November, 2007 generation capacities and related transmission Page 2 (12) Task 3.1.B – Ash utilization


Disclaimer

While the consortium of Pöyry, CESI, TERNA and DECON considers that the information and opinions given in this work are sound, all parties must rely upon their own skill and judgement when making use of it. The consortium members do not make any representation or warranty, expressed or implied, as to the accuracy or completeness of the information contained in this report and assumes no responsibility for the accuracy or completeness of such information. The consortium members will not assume any liability to anyone for any loss or damage arising out of the provision of this report. The report contains projections that are based on assumptions that are subject to uncertainties and contingencies. Because of the subjective judgements and inherent uncertainties of projections, and because events frequently do not occur as expected, there can be no assurance that the projections contained herein will be realised and actual results may be different from projected results. Hence the projections supplied are not to be regarded as firm predictions of the future, but rather as illustrations of what might happen. Parties are advised to base their actions on an awareness of the range of such projections, and to note that the range necessarily broadens in the latter years of the projections.



Table of Contents

1 INTRODUCTION..............................................................................................................4

2 CONSTRUCTION INDUSTRY .......................................................................................4

2.1 Clinker and blended cements ...............................................................................................5 2.2 Concrete production .............................................................................................................6 2.3 Brick industry.......................................................................................................................8 2.4 Ceramic tiles industry...........................................................................................................9 2.5 Quality control......................................................................................................................9 2.6 Environmental restoration ....................................................................................................9

3 CONCLUSION.................................................................................................................10

TABLES Table 4-1 EN 197-1:2004: The 27 products in the family of common cements……….…………...11 Table 4-2 Fly ash chemical and physical requirement for production of concrete according to EN 206-1 e EN 450-1……………………………………………………………………………….12



1 INTRODUCTION The ash in the fuel entering the boiler furnace exits the combustion process through two different routes: Fly Ash represents the particulate matter captured by electrostatic precipitators (ESP) from the exhausted gases of combustion. During the thermal combustion process the mineral fraction of lignite melts at the furnace temperature in case of applying pulverized firing method and a small part of it (10-20 %) falls in the bottom of the furnace, producing the so-called bottom slag. The main part (90-80 %) is captured by the flue gas stream. It solidifies in form of small spherical particles while cooling down which form the so-called fly ash. Fly ash is a fine grey powder (means diameter particles is between 1-100 µm) and is characterised by the presence of high contents of silica, calcium oxide, alumina and ferrous oxide with lower content of residual unburned carbon. In case of applying Circulating Fluidized Bed (CFB) combustion the maximum temperatures in the furnace do not reach melting point (<950-1000 °C) and the heavy coarse fraction of fuel ash exits as bottom ash through the fluidizing grate. The proportional share of that bottom ash is roughly the same as with pulverized firing. Depending on chemical composition, lignite fly ash exhibit pozzolanic and/or hydraulic properties. In Europe, the principal coal fly ash fields of destination are:

1) Construction industry (46%) 2) Environmental restoration (43%) 3) Temporary stockpile (6%) 4) Landfill disposal (5%)

From technical and legal point of view, in the field of construction industry lignite fly ash have almost the same potential destinations as coal fly ash, depending on its chemical and physical characteristics. In addition lignite fly ash is the better material for environmental restoration.

2 CONSTRUCTION INDUSTRY The potential fly ash reuses in the construction materials production are: 1) Clinker and blended cements 2) Concrete 3) Clay tiles 4) Aggregates



2.1 Clinker and blended cements It is possible to introduce fly ash directly into cement mixture preparation. It is uneconomical to reuse from the dumps but it is useful to avoid temporary storage and landfill disposal. It is recommendable to verify this way directly by local cement producers. In Europe Fly Ash is added to clinker in the production of Blended Cements with respect to the local and European quality standards. Types of Common Cements, Chemical and physical properties for fly ash to be utilised in blended cement and procedures for quality control are specified by communitarian standard EN 197-1 “Cement Composition, specifications and conformity criteria for common cements”. EN 197-1. It defines and gives the specifications of 5 main classes and 27 individual types of common cement that comprise Portland cement as a main constituent (see Table 1 in Appendix). These classes differ from the ASTM classes. The definition of each cement type includes the proportions in which the constituents are to be combined to produce these distinct products in a range of six strength classes. The definition also includes requirements the constituents have to meet and the mechanical, physical and chemical including, where appropriate, heat of hydration requirements of the 27 products and strength classes. EN 197-1 also states the conformity criteria and the related rules. Necessary durability requirements are also given. Constituents that are permitted in Portland-composite cements are blast furnace slag, silica fume, natural and industrial pozzolans, silicious and calcareous fly ash, burnt shale and limestone. Two major classes of fly ash are specified in EN 197-1 on the basis of their chemical composition resulting from the type of fuel burned: “Siliceous Fly Ash” and “Calcareous Fly Ash”. The combustion of lignite normally produces calcareous fly ash that usually exhibit cementic properties (in addition to pozzolanic properties) due to free lime. This expected composition is confirmed by chemical analysis performed on samples coming from Kosovo B and verified by the lignite ash analysis made in this study work. On the basis of characterisation actually available lignite fly ash may be reused in the production of Portland-Fly Ash Cement Type CEM II/A-W (fly ash added 6-20 %) and Type CEM II/B-W (fly ash added up to 35 %), Portland-composite Cement (Type CEM II) and Composite Cement (Type CEM V). In the following table are reported the chemical and physical requirements for calcareous fly ash utilised in cement production:

CaO active >10% SiO2 active >25% Expansivity <10 mm



If a high gypsum content in fly ash is expected, the exact amount of fly ash added to cement must be determined with respect to gypsum limit in cement.

2.2 Concrete production Fly ash can be introduced in concrete formulation both as pozzolanic addition (the most valuable final destination) and as inert aggregates. In Table 2 requirements of standard EN 450 are summarised, indicating chemical-physical properties and statistical control criteria for fly ash to be utilised in the production of structural concrete conforming to the standard EN 206. On the basis of chemical characterisation actually available, the lignite fly ash from Kosovo does not comply with this requirement due to higher free calcium content. Nevertheless several studies show that also calcareous fly ash may be introduced in the concrete formulation obtaining final products that reaches commercial standard specification (mechanical strength, durability, etc.). According to EN 206, fly ash can be introduced as a pozzolanic addition in concrete mixdesign with an equivalent factor k = 0,2 or 0,4, depending on the cement class, with respect to the minimum Portland cement content required by the standard for each class of environmental exposition of the final product. The substitution rate of fly ash for Portland cement will vary depending upon the chemical composition of both the fly ash and the Portland cement. It should be noted that the amount of fine aggregate will have to be reduced to accommodate the additional volume of fly ash. This is due to fly ash being lighter than the cement. Effects of the fly ash on fresh and hardened concrete properties have been extensively studied by many researchers in different laboratories. The two properties of fly ash that are of most concern are the carbon content and the fineness. Both of these properties will affect the air content and water demand of the concrete. The finer the material the higher the water demand due to the increase in surface area. The finer material requires more air-entraining agent to mix the desired air content. The important thing to remember is uniformity. If fly ash is uniform in size, the mix design can be adjusted to give a good uniform mix. The carbon content, which is indicated by the loss of ignition (LOI), also affects the air entraining agents and reduces the entrained air for a given amount of air-entraining agent. An additional amount of air-entraining agent will need to be added to get the desired air content. The carbon content will also affect water demand since the carbon will absorb water. Again uniformity is important since the differences from non-fly ash concrete can be adjusted in the mix design. Fresh Concrete Workability. Use of fly ash increases the absolute volume of cementitious materials (cement plus fly ash) compared to non-fly-ash concrete; therefore, the paste volume is increased, leading to a reduction in aggregate particle interference and enhancement in concrete workability. The spherical particle shape of fly ash also participates in improving workability of fly ash concrete because of the



so-called "ball bearing" effect. It has been found that both classes of fly ash (siliceous and calcareous) improve concrete workability. Bleeding. Using fly ash in air-entrained and non-air-entrained concrete mixtures usually reduces bleeding by providing greater fines volume and lower water content for a given workability. Although increased fineness usually increases the water demand, the spherical particle shape of the fly ash lowers particle friction and offsets such effects. Concrete with relatively high fly ash content will require less water than non-fly-ash concrete of equal slump. Time of Setting. All fly ashes class increase the time of setting of concrete. Time of setting of fly ash concrete is influenced by the characteristics and amounts of fly ash used in concrete. For highway construction, changes in time of setting of fly ash concrete from non-fly-ash concrete using similar materials will not usually introduce a need for changes in construction techniques; the delays that occur may be considered advantageous. Strength and Rate of Strength of Hardened Concrete. Strength of fly ash concrete is influenced by type of cement, quality of fly ash, and curing temperature compared to that of non-fly-ash concrete proportioned for equivalent 28-day compressive strength. Concrete containing typical siliceous fly ash may develop lower strength at 3 or 7 days of age when tested at room. However, fly ash concretes usually have higher ultimate strengths when properly cured. The slow gain of strength is the result of the relatively slow pozzolanic reaction of fly ash. In cold weather, the strength gain in fly ash concretes can be more adversely affected than the strength gain in non-fly-ash concrete. Therefore, precautions must be taken when fly ash is used in cold weather. Freeze-thaw Durability of Hardened Concrete. On the basis of a comparative experimental study of freeze-thaw durability of conventional and fly ash concrete, it has been observed that the addition of fly ash has no major effect on the freeze-thaw resistance of concrete if the strength and air content are kept constant. The addition of fly ash may have a negative effect on the freeze-thaw resistance of concrete when a major part of the cement is replaced by it. The use of fly ash in air-entrained concrete will generally require an increase in the dosage rate of the air-entraining admixture to maintain constant air. Air-entraining admixture dosage depends on carbon content, loss of ignition, fineness, and amount of organic material in the fly ash. Carbon content of fly ash, which is related to the coal burned by the producing utility of the type and condition of furnaces in the production process of fly ash, influences the behavior of admixtures in concrete. It has been found that high-carbon-content fly ash reduces the effectiveness of admixtures such as air-entraining. Alkali-silica Reaction of Hardened Concrete. One of the important reasons for using fly ash in highway construction is to inhibit the expansion resulting from ASR. It has been found that 1) the alkalies released by the cement preferentially combine with the reactive silica in the fly ash rather than in the aggregate, and 2) the alkalies are tied up in non-expansive calcium-alkali-silica gel. Thus hydroxyl ions remaining in the solution are insufficient to react with the material in the interior of the larger reactive aggregate particles and disruptive osmotic forces are not generated. In a paper



presented at the 8th International Conference on alkali-aggregate reactivity held in Japan in 1989, Swamy and Al-Asali indicated that ASR expansion is generally not proportional to the percentage of cement replacement by fly ash. The rate of reactivity, the replacement level, the method of replacement, and the environment all have a profound influence on the protection against ASR afforded by fly ash. Several investigators have stated that ASR expansions correlated better with water-soluble alkali-silica contents than with total alkali content. The addition of some high-calcium fly ash containing large amounts of soluble alkali sulfate might increase rather than decrease the alkali-aggregate reactivity. The effectiveness of different fly ashes in reducing long-term expansion varied widely; for each fly ash, this may be dependent upon its alkali content or fineness. Restraints on the Use of Fly Ash Concrete in Highway Constructions: It is well known now that both classes of fly ash improve the properties of concrete, but several factors and cautions should be considered when using fly ashes especially in highway construction, where fly ash is heavily used. Several restraints relating to the use of fly ash concrete for construction of highways and other highway structures were discussed. These restraints include the following: 1) special precautions may be necessary to ensure that the proper amount of entrained air is present; 2) not all fly ashes have sufficient pozzolanic activity to provide good results in concrete; 3) suitable fly ashes are not always available near the construction site, and transportation costs may nullify any cost advantage; and 4) mix proportions might have to be modified for any change in the fly ash composition. Since the cement-fly ash reaction is influenced by the properties of the cement, it is important for a transportation agency not only to test and approve each fly ash source but also to investigate the properties of the specific fly ash-cement combination to be used for each project.

2.3 Brick industry Utilisation of fly ash as a resource in building bricks production was extensively studied but the industrial applications are still low. A major factor preventing a large -scale utilisation is the difficulty of producing quality –controlled materials that can meet market specification. Building bricks are usually made of a mixture of clay and sand, which are mixed and moulded in various ways, dried and burned. Clay for bricks production must develop proper plasticity and drying without excessive shrinkage, warping or cracking. The final product must exhibit the desired texture and strength. Several solutions was proposed and their effectiveness experimentally verified. Fly ash can added to mix in



proportion up to 40-60 % but also 100 % fly ash bricks were produced with good appearance and mechanical properties. In any case specific procedures for mixing drying and firing must be followed in order to obtain final products.

2.4 Ceramic tiles industry

Fly ash can be used as partial replacement for clay in the ceramic tiles industry. A wide variety of experimental studies and industrial applications is available in literature. High unburned carbon content is the most important characteristic of fly ash that may have an adverse effect on the process suitability. Whereas carbon is easily burned out on the tile surface, its particles can be entrapped inside the tile body and cause a wide range of defects. Slow burning is the practically feasible measure to remove unburned carbon and alleviate these effects.

2.5 Quality control The expected production rate of lignite fly ash is very high (around 70-80 t/h for a 500 MW unit) and the storage capacity at power plant station cannot cover some days. Therefore, the power plant station is interested to guarantee a full and constant fly ash reutilization regime, obtaining at the same time a necessary operational continuity and an economical valorisation of its by-product. It is needed a quality control system that makes lignite fly ash more similar to an industrial product rather than a waste refuse. This quality control system involves procedures of combustion control, ash collection and managing, collection and analysis of representative samples and statistical evaluation of data. This system is intended to guarantee that the technical and normative requirements for each potential reuse are reached and the quality variations are minimised.

2.6 Environmental restoration Lignite fly ash is a good material for environmental restoration due its latent hydraulic properties that makes it similar to “natural cement”. Lignite fly ash, mixed only with proper amount of water, produce a fluidised and fluid material that solidifies assuming useful particular geotechnical properties and high resistance to leaching. Other ligands are not required and therefore the operation is inexpensive. Metals and other pollutants, eventually presents in fly ash, are immobilised in cementitious matrix. For example, lignite fly ash can be applied to prevent acidic mine drainage from exhausted underground mine even in conjunction with FGD-Gypsum, another by-product available at the power plant station. Several examples of this type of application are reported in literature.



3 CONCLUSION

Environmental legislation and technical standards in Europe consider fly ash as a usable and profitable raw material for the obtainment of several products, with particular relevance in cement production and possibly even in concrete mix design. Lignite fly ash role and benefits have been widely recognised in literature, but power plant station is pushed to pursue their quality if they want to create a stable market of destination and guarantee normal running conditions of thermoelectric generation. Unburned carbon content often results as the most critical parameter for reuse in concrete mix design, while fly ash fineness is its most valuable characteristic. Fly ash post-treatment beneficiation processes for unburned carbon removal have the disadvantage to treat the entire ash production, with consequent high costs of investment and exercise. Fly ash selection inside the power plant and its partial recirculation into the boiler could represent simpler alternatives for fly ash quality improvement. Selection could be based on natural differences in fly ash quality when collected at electrostatic precipitator hoppers, while re-burning of high carbon fractions will avoid the definition of a refused ash stream. Eventually, further demand of unburned carbon separation could be persecuted by sieving selected ash streams, with the advantage of reducing the treatment capacity and obtaining a better efficiency and productivity with respect to those typical of the raw material treatment. For the other destinations, as clinker, blended cement bricks and ceramic tiles production, unburned carbon is not so critical but fly ash fineness is important to achieve commercial specifications required for the market. The proposed plant will be in base load operation and it can be expected that its combustion processes can be tuned to produce uniform quality ash for cement manufacturing or environmental restoration (including road construction). The new plant easily can provide the facilities to load a part of the fly ash/slag onto trucks. Anyhow the ash generation is around 2,5 million annual tons while the plant is fully developed. There must be a place to dump the ash in the old Mirash mine if the ash market cannot absorb all the production of the fly ash.

November, 2007


Contract nr 122521/D/SER/KOS


CONSORTIUM OF PÖYRY, CESI, TERNA AND DECON

Task 3.1.C

Plant maintenance practises

Studies to support the development of new generation capacities and related transmission Page 2 (15) Task 3.1.C. Plant Maintenance practises November, 2007


Disclaimer




Table of contents 1 Introduction................................................................................................................................4 2 Maintenance overview ...............................................................................................................4

2.1 Maintenance of main components in common for both technologies ..........................7 2.1.1 Coal transportation system .......................................................................................7 2.1.2 The boiler ....................................................................................................................7 2.1.3 The steam turbine ......................................................................................................9 2.1.4 Steam condenser.........................................................................................................9 2.1.5 Air – gas circuit ..........................................................................................................9 2.1.6 Desulphurisation system............................................................................................9 2.1.7 Electrical equipment ................................................................................................11 2.1.8 Instrumentation........................................................................................................11 2.1.9 Overhauls..................................................................................................................12

2.2 Spare parts........................................................................................................................12 2.3 The maintenance team.....................................................................................................14



1 INTRODUCTION This report reviews the general maintenance requirements, inspection intervals and spare parts stocks that are typical for the technologies considered in this study and earlier executed prefeasibility study.

2 MAINTENANCE OVERVIEW Maintenance includes a number of activities with the goal to preserve the operational capacity, the efficiency and the reliability of the plant at an acceptable level, but without modifying its characteristics. Therefore, it is quite evident that a wide range of actions may be considered as maintenance. A rough classification may include the categories as follows:

• cleaning: fouling, soot, deposits, dust may affect the operation and the performance of some components, therefore periodic cleaning is recommended. In some cases automatic cleaning systems are installed (soot blowers in the boiler and heat exchangers on gas flows, cleaning systems in the condensers, etc.). However, in many cases manual interventions are requested. For instance, an yearly cleaning of the condenser tubes and cooling water circuit is usually recommended. Also fans, heat exchangers, external electric insulators, etc. should be periodically subject to cleaning operations. Cleaning interventions usually require the component out of service;

• periodic inspections on components, with the aim to verify their conditions;

such inspections may be as follows: o visual: to be performed by means of inspection ports, windows,

opening of manhole covers; they do not require the dismounting of the components or special equipment; they are aimed to detect evident degradations and conditions which may lead to faults (cooling and lubricating fluids levels, corrosion and erosion conditions, clearances, etc.)1

o instrumental: as visual, but using special equipment for specific measurements (clearances, allowances, positions, erosions, corrosions, material characteristics, etc.)

The result of such inspections may be the identification of the need of repairs, replacements, refills, adjustments, regulations. The frequency of such inspections is usually predefined and may vary between once a day, for instance for the fluid levels, and once every 10 000 operating hours, for instance for the steam turbine blades. However, some inspections may be requested in case of some proved or suspected events and observations eg. high vibration/noise levels.

1 Visual inspections should not be confused with monitoring during the operation: the formers usually require the temporary stop of the component and the participation of the maintenance team. Monitoring is performed during operation and performed by the operation personnel.



• periodic replacement of some parts, according to indications of the manufacturer (oil change, replacement of parts at the end of their planned life). Such replacements are very important when a breakage due to planned consumption may provoke serious damages to some parts of the unit.

• interventions on demand, for repairs, replacements, refills, adjustments,

regulations, with the aim to restore expected functional parameters of the components and the unit. The need of such interventions may result from the inspections performed on the plant components;

• major planned overhauls on main components, such as turbines, boiler, coal

mills, regenerative gas-air preheaters, electrostatic precipitator or flue gas desulphurizer plant etc..

The lack of any of the aforementioned maintenance activities is often the cause of abnormal degradations, faults and breakages, which may often induce production losses and stops of the plants. Maintenance cost and downtime losses of a power plant can be reduced by adopting a proper mix of maintenance strategies that ensure its reliable availability. The type of maintenance for different equipment in a power plant is decided as per its importance in terms of attributes, such as maintenance efforts and costs, loss of production, safety/reliability and efficiency. In the worst situation, failure of hypothetical equipment would affect all these attributes and would thus have maximum criticality. In general, the failure of equipment would not affect all the attributes and therefore its criticality will have some intermediate value. The level of criticality would decide the importance of the power plant equipment and choice of appropriate maintenance strategy. More in details, in the case of a coal-based power plant, the availability of auxiliary equipment is very important for the achievement of maximum generation and the improvement of plant load factor (PLF). In this context a realistic maintenance programme, preferably prepared in co-operation with the manufacturers of main components and based on plant-specific failure data, will help to achieve an optimum performance level. The organisation of maintenance activities has to consider that some actions need a deep knowledge of the components, or special equipment, or have to be performed on a very short notice. The choice on how to perform maintenance activities has to take some aspects into consideration. In particular, one of the main issues to be evaluated regards the executors of such actions, which may be internal of the power plant or an external supply. The discussion at this regard should consider that:

- some activities can be planned in advance, therefore the relevant service can be provided by an external company, even if it is not available to intervene on a very short notice;



- some others cannot be planned in advance, therefore relevant interventions should be assigned to a local team, either of the power plant or external, but immediately available;

- some services can be performed by means of special equipment (for instance, special cranes). In case such equipment is not easily transportable, they must be available on site. In a country like Kosovo, where industrial market is not much developed, such specialised companies may not be available and the need of the power plant to have such special equipment may be unavoidable or the fast delivery should be pre-organized;

- the same consideration may regard the skills of the experts who can provide the required services and how frequent their service may be requested. A good example of this is a tube failure in the superheater which would need special welding/welder and heat treatment capacities. For short and simple works it may be not convenient to call international experts. At the same time, reliable experts may be not available on call. In this case their presence in the internal maintenance team is unavoidable;

- some services may be requested only occasionally in the power plant, but they may be of interest also for other external industries. This is the case of the cleaning companies. In this case the assignment of this services to external companies, which can be equipped with water jet cleaners and other suitable machinery, is surely more applicable.

Taking also these aspects into consideration, the following more detailed considerations can be done. Different combustion technologies are discussed to identify specific problem areas and approaches.



2.1 Maintenance of main components in common for both technologies Pulverised coal technology Fluidised bed technology

2.1.1 Coal transportation system An interruption of the coal supply provokes a lack of power generation. In order to minimise the possibility of such event, each unit is equipped with a daily storage silos at the boilerhouse. However, the reliability of the coal transportation system remains a critical issue, to be minimised by means of a suitable maintenance. Nevertheless, the transportation systems are often subject to faults, which must be solved in a short time, in order to avoid major damages and interruptions in the fuel supply to the furnace. Therefore it is necessary that the power plant is equipped with its own maintenance team, ready and able to intervene and solve minor problems; moreover spare parts, such as conveyor parts and bearings, must be available on site. In this case it is recommended to integrate these activities with the mine as there are even more conveyors.

2.1.2 The boiler Regardless the very different combustion technology applied to the furnace, several maintenance activities are similar for the different technologies applied for the boiler. Excluding the continuous soot blowing, which can be considered as an operation procedure rather than a maintenance one, many other interventions at different levels are necessary. The most frequent are related to soot and slagging removal (soot blowers) and overheating of some tubes. In particular, soot and slagging may represent the most important issue of the boiler, especially if not properly designed for some kinds of coals with bituminous and low melting point ashes (like in the case of Sibovc lignite). The need of replacement of some tubes or tube sections is quite frequent and the on-site team must be able and equipped to provide tube welding and heat treatments according to the requirements of the special materials used for the boiler tubes. Also the combustion system (flame detectors, auxiliary fuel burners) is often object of repairs and interventions. On a long term basis, namely after 100 000 – 200 000 operating hours, also the replacement of the most stressed parts, such as some tube bundles operating at the highest temperatures, may be necessary although the current practise is to design the parts for 200.000 hours what regards to thermal fatique. Finally, the ash removal conveyors and devices require periodic inspections and repairs. More specific activities are related to the technology applied. In the case pulverised lignite firing is used, specific maintenance activities are limited to the regulation of air flows into the boiler, including the gas recirculation fans and air locks.

In the boiler using the fluidised bed technology another part which may be subject to faults and maintenance interventions is the ash recirculation system of the furnace. Fans, cyclones, air locks, ducts, etc. are subject to high stresses due to high temperatures and the aggressive particulates in circulation. Moreover, this technology has not widely proven for large power plants, therefore it is highly probable that the lack of experience has to be compensated with a more or less intensive



Pulverised coal technology Fluidised bed technology maintenance operation.

Usually most frequent repairs are performed by internal staff of maintenance team, whilst heavier interventions (replacement of tube bundles, collectors, conveyors, etc.) are carried on by the manufacturer, often in co-operation with the internal maintenance team. In the latter case, the role of the internal maintenance team is to monitor the operating conditions of the components, in order to plan major overhauls and other manufacturer interventions. Specific spare parts usually include some superheater tubes and wall tubes, for replacement of limited damaged parts, and devices related to the combustion (flame detectors, start-up or secondary fuel burners and relevant nozzles, etc.). Lignite pulverizers Lignite mills must be able to operate for a time span of some thousands of hours, especially if the soft lignite of Sibovc is used. In this specific case, maintenance intervals up to 4000 operating hours can be foreseen. However, specific problems, needs of regulations and stops of a mill (with a possible load reduction) are not infrequent. The performance of a mill, especially when the fuel quality varies, is directly related to the load produced and indirectly impacts other areas such as slagging, ash sales and opacity of the exhaust gas. This is particularly true for example when large pyrite particles escape from the mill and do not completely oxidise in the flame. Such mill performance is strongly influenced by its maintenance and may depend on several parameters and primary air flow. Consequently, it is strongly recommended to install one or two spare mills. In addition, it is preferable that the maintenance team on-site is able to intervene on lignite mills.



Pulverised coal technology Fluidised bed technology

2.1.3 The steam turbine The steam turbine is highly reliable and usually does not require special maintenance interventions. Typically, boroscope inspections can be performed every 25 000 operating hours (3 years) without opening hot casing. Major overhauls are usually planned every 50 000 to 100 000 operating hours2. They are performed by the manufacturer or other specialised companies. Internal maintenance team monitors the degradation of the turbine by means of visual inspections with boroscopes during turbine stops. The choice to have spare blades, or even a spare rotor, may depend on commercial considerations, aimed to reduce the dependency from an unique supplier. In case of a new generation unit, the negotiation of a contract for O&M with the supplier would be recommended till the first major overhaul, including the supply of some spare blades for the hottest section and for the wet stages. Some lubricating oil for refilling should be made available at any time.

2.1.4 Steam condenser The steam condenser and the cooling circuit require periodic cleaning interventions. In most cases such activities are contracted to external companies, equipped with suitable water jet cleaners and employing workers with a low education. In the East European countries like Kosovo, where very often staff in the power plants is very large and local companies very few, such cleaning activities are performed by the internal maintenance team. No specific spare parts are needed

Steam circuit Periodic inspections are needed for pumps and valves. The reliability of main pumps and their cost are quite high, therefore no major spare components are usually made available at the power plant, except for smaller equipment and components. The same criterion is applicable to the valves.

2.1.5 Air – gas circuit Air – gas lines usually do not require maintenance interventions during operation, except some occasional repairs for leakage or corrosion. More important overhauls are periodically needed for the regenerative air – gas heat exchanger (Ljungstroem heat exchanger), in order to replace corroded internal baskets and gaskets. Usually such works are performed by the manufacturer, who can supply and install the new parts. No specific spare parts are usually needed, at least for sometimes after the start-up of the unit. However, it may be a good choice to ask the manufacturer of the power plant to provide some spare components which are more frequently changed (gaskets, baskets for the air-gas heat exchanger, etc.). Finally, in case of replacement of fans, motors and other major components, it may be useful also to recondition and keep them as spare components for future substitutions

2.1.6 Desulphurisation system The Flue Gas Desulphurisation system (FGD) is required to reduce sulphur emissions when

Desulphurisation does not require specific components: calcium carbonate can be added in

2 Russian manufacturers used to require an overhaul every four years, regardless the number of (equivalent) operation hours. However it is foreseen that in the future the trend will be to prolong such interval to at least 50 000 operating hours or even more.



Pulverised coal technology Fluidised bed technology pulverised coal is used. A FGD plant is almost as large and complex as the boiler and it requires proper maintenance. Some problems have been experienced with the limewater circulation pumps, which have to be carefully monitored and maintained. Cyclones are subject to erosion, loosing their separation capacity, therefore they need periodical inspections. A full set of spare cyclones are strongly recommended. The protective coatings need extensive inspections and care. The operation of an FGD unit strongly depends on chemical measures and metering, therefore relevant devices and equipment is constantly maintained. Due to its dimensions and complexity, the presence of an FGD may represent a 30% of maintenance costs of the whole unit. For the same reason, internal maintenance team and the manufacturer usually co-operate, the former performing daily monitoring and minor repairs and replacements, the latter providing major periodic interventions and overhauls.

the fluidised bed, where it can react forming gypsum and be extracted with the ashes (in this particular case the fuel contains enough limestone for desulphurization – no need to add limestone). Therefore, specific maintenance may interest the batch system for the calcium carbonate



Pulverised coal technology Fluidised bed technology

2.1.7 Electrical equipment Almost any intervention for maintenance, overhauls and repairs interest the electric system and its relevant equipment. Therefore an internal maintenance team with good skills in the electric fields is absolutely necessary. They must be able to provide connections and disconnections, replacement and repairs of all electric components, with the only exception of those for which special equipment and experience is required, such as for instance the alternator and the step up transformer. Periodic cleaning of external insulators and components from soot and dust may be recommended, in order to avoid short circuits and sparks towards ground, especially in case of rain (it should be remembered that lignite dust is conductive). This work can be done also by an external team equipped with water jets (under a strict supervision of internal staff, in order to avoid energised parts). However, fire fighting devices can also be used by internal maintenance team. Spare parts usually include a main switch, an auxiliary transformer, an exciter for the alternator, insulators, components for boards and panels, UPS system components, cables, etc.. Some oil for refilling should be available, as well. Step-up transformers are really critical for the plant operation, but their cost is also very high. Moreover, the supply for replacement of a new one may require up to two years. Therefore, usually a large electric utility has one spare transformer available for all the power plants of the same size. In the case of the new Kosovo power plant, it should be evaluated if it may be possible to store a spare step-up transformer both for Kosovo B and for the new power plant. In any case, it may be anyway preferable to have a spare transformer for the four proposed units. It is also important to remind that a spare step up transformer must be regularly maintained, checking oil level, keeping it dry and clean from soot and rust, otherwise the probability of fault after the replacement are very high.

2.1.8 Instrumentation The instrumentation needs periodical verification and calibration. The daily activities related to verifications and replacements must be performed by an internal maintenance team, which has to be ready to intervene on short notice. That is why it is assumed to have a technician working in shift in order to be present whenever minor problems would surface up. The periodical calibrations could be performed in an internal instrumentation laboratory or by an external service company, depending on the capabilities of internal staff and economic convenience. In any case the power plant needs a number of spare sensors and transmitters able to cover all the urgent needs for the operation of the unit (pressure transmitters with different ranges, thermocouples, thermo-resistances, flame sensors, instruments for electrical and chemical measures, etc.).



2.1.9 Overhauls

The useful life of the main equipment of the power plant is assumed to be 200.000 hrs or 40 years. However, an annual/periodic overhaul is necessary, in order to inspect the conditions of the equipment/machinery, provide the required maintenance and repairs and allow a reliable operation. Most activities for such overhauls could be performed by the internal staff, in some cases under the supervision of the manufacturer experts, as it might be in the case of the alternator or the turbine. Nowdays the tendency is to shorten the stopping time and with good preplanning work in two shifts i.e. the plant personnel is not sufficient for that kind of work and a lot of outside contractors are employed with the supervision of the plant personnel. Any activity to be performed during the shutdown must be carefully planned and co-ordinated, in order to assure that the available staff, equipment and instrumentation can be efficiently used, avoiding useless waiting time. To this aim, such planning has to be prepared throughout the year, taking note of all interventions which are to be performed during the shutdown and preparing materials and spare parts needed. A few days before the shutdown, several works can be performed, for instance preparing scaffolds, removing the turbine box, installing cranes and hoists, etc.. The duration of an annual overhaul of each unit is 3-4 weeks.

2.2 Spare parts

The definition of spare part to be held available for the unit depends on several aspects, such as: • the maintenance philosophy: theoretically, any major spare part could be

purchased on demand. However, in most cases the supply time would be very long and costs quite high. On the contrary, a large amount of spare parts and components could be made available at the power plant, but costs would be higher, because of the capital tied up, storage space and periodic maintenance of those spares. In general, the most convenient solution is in between the two extreme possibilities. For some components, such as the steam turbine or the alternator, a long term maintenance contract with the manufacturer may reduce the need of spare parts, under the condition that such spare parts are made available by the manufacturer himself. In particular, the manufacturer may be requested to provide turbine blades, bearings and seals for the maintenance activities;

• the redundancy of the unit equipment, such as pumps, valves, heat exchangers, etc.: in fact, redundant components represent spare parts already installed and ready to operate. In particular, usually a power plant is equipped with 2 x 100 % or 3 x 50 % feedwater pumps, one or two spare pulverizers, 3 x 50 % cooling heat exchangers for the alternator, etc. A working solution is also a case where there is only one running unit installed but all the rotating/wear parts are in warehouse for immediate replacement in failure eg. large crushers;



• the number of power plants which can share the spare parts: if there is only one unit, the cost of a spare step-up transformer, a turbine rotor or a switchgear may be too high. On the contrary, a spare unit which can be made available for four similar units, as in the case of the new power plant, may be justified. For this reason, standardisation of the units is very important.

The aims of making some spare parts and components available may be different:

• they may improve the reliability of the unit, when the time for restoring the full operation conditions may be significantly affected by the availability of spare parts. In this case, the convenience of keeping a spare part can be defined comparing the cost of the storage with the lack of production due to the unavailability of spare parts. Such comparison indicates that, for instance, spare pulverizers, coal transportation belts and relevant bearings are recommended. This may be the case also of some components which are critical for the plant operation, and their possible faults may cause a long stop of the unit. The supply of a new step-up transformer /steam turbine drive of the feed water pump would require one or even two years, during which the unit is blocked. In this case, even if the spare unit may be very expensive, it may be recommendable to have one, especially if it can be made available for several installed units.

• they give more flexibility in the maintenance management, either in the planning (freedom in choosing the most convenient time for interventions, without waiting for the availability of the spare parts) or in the organisation (the spare part purchase and the replacement activities can be managed separately);

• their price can be more effectively negotiated if not under pressure for the urgency of the replacement. This is particularly true if the spare parts are purchased together with the overall unit. This is usually the case of turbine hot section or wet stage blades, pulverizer parts, transformers, switchgears, etc.).

The storage of spare parts has a cost due to: • the payment which may be made even some years in advance with respect to the

actual needs • the related maintenance activities (for instance, protection against corrosion and

degradation due to humidity, dust and soot) • the space for their storage.

Typically the need of spare parts increases with the age of the equipment. Consequently, it would be more convenient to purchase spare parts and components after the first years of operation. However, the risk is that such purchase is delayed too much, beyond the first needs, thus loosing all the advantages of such choice. In case of fault of a component, its replacement, rather than its reparation, allows to reduce the time for the shut down of the unit. In this cases, the replaced parts or equipment can be repaired and kept available as spare for future needs of the some or other units.



2.3 The maintenance team In Eastern Europe lignite fuelled power plants, the staff working in maintenance teams may include up to 300 – 400 persons at different levels of education. However such composition seems to be more related to political and social reasons rather than real technical needs. Todays practise is that the plants just have personnel to run the plant and take care of daily check-ups and maintenance interventions. Any real maintenance work eg. on a pulverizer (to open it and change the beater wheel at 4000 hrs intervals) would be done by contractors under the supervision of the plant personnel. On the base of the aforementioned considerations, a reasonable composition of a maintenance staff for a new power plant in Kosovo has already been proposed in the pre-feasibility study, where, not considering the mines, the plant operation and the management, the involvement of the following staff has been assumed:

Staff No. for the first

unit No. for the following units

Engineers for boilers 2 1 Engineers for turbines 2 1 Chemical engineers for water and fuel

2 -

Electrical engineers 2 1 I&C engineers 2 1 Engineers for scheduling 2 1 Mechanical supervisors 9 5 Electrical supervisors 4 2 I&C supervisors 4 2 Other supervisors 2 2 Mechanical experts in shift 5 2 Electrical expert in shift 5 1 I&C expert in shift 5 1 Mechanical staff for day work 5 5 Electrical staff for day work 5 5 I&C staff for day work 5 5 Laboratory staff for day work 3 - Other staff 10 5 TOTAL 74 40

The aforementioned staff should be trained by the manufacture, in order to be able to operate on the equipment at a certain level of autonomy. At least 5 persons should be qualified for welding on components under pressure, typically steam pipes and boiler



tubes, especially in the case of supercritical boilers, for which new high temperature materials are used.

November, 2007

European Agency for Reconstruction Contract nr 05KOS01/04/005


CONSORTIUM OF PÖYRY, CESI, TERNA AND DECON Task 3.1.D

TECHNOLOGY REVIEW

Studies to support the development of new generation capacities and related transmission Page 2 (49) Task 3.1.D. Technology review November, 2007


Disclaimer




CONTENTS

1 INTRODUCTION..................................................................................................................4

2 STEAM CYCLE POWER PLANTS....................................................................................4

2.1 Steam parameters and plant overall efficiency ........................................................................4 2.2 Materials for high temperatures ...............................................................................................6

3 STEAM BOILERS.................................................................................................................8

3.1 Lignite analysis ........................................................................................................................8 3.2 Pulverized fired boilers ..........................................................................................................10 3.3 Circulating Fluidized Bed combustion ..................................................................................13 3.4 Lignite drying.........................................................................................................................16

4 EMISSION CONTROLS ....................................................................................................22

4.1 Desulphurization ....................................................................................................................22 4.2 Wet scrubbers for SO2 control...............................................................................................22 4.3 Spray dry scrubbers for SO2 control......................................................................................24 4.4 Sorbent injection systems for SO2 control ............................................................................25 4.5 Dry scrubbers for SO2 control ...............................................................................................26 4.6 Regenerable processes for SO2 control .................................................................................27 4.7 Flue gas discharge –stack vs. cooling tower ..........................................................................27

5 STEAM TURBINES............................................................................................................29

5.1 Material selection...................................................................................................................29 5.2 Steam turbine High pressure and Intermediate pressure casings...........................................30 5.3 Number of LP turbine casings ...............................................................................................31 5.4 Turbine condenser..................................................................................................................31 5.5 Generator................................................................................................................................33

6 IGCC (INTEGRATED GASIFICATION COMBINED CYCLE) .................................34

6.1 Background ............................................................................................................................34 6.2 Process description.................................................................................................................34 6.3 Classification of gasifiers.......................................................................................................35 6.4 Performance without CO2 capture..........................................................................................36 6.5 Conclusions............................................................................................................................44

7 CO2 - CAPTURE..................................................................................................................46



1 INTRODUCTION This report presents and discusses potential technical concepts for large scale power generation on lignite.

2 STEAM CYCLE POWER PLANTS

2.1 Steam parameters and plant overall efficiency The initial selection of the steam parameters has a fundamental effect on the plant overall efficiency. It basically fixes the plant operating parameters for the whole life as their modification especially upwards would be far too costly. In order to have an idea on the impact of the following table summarizes the typical overall net efficiency (LHV) vs. steam parameters in a single reheat plant firing conventional steaming coal:

HP-steam RH-steam Efficiency pressure/temperature temperature

167 bar / 538 °C 538 °C 41,5 %

240 bar / 540 °C 560 °C 43,0 %

270 bar / 580 °C 600 °C 44,5 %

285 bar / 625 °C 620 °C 45,3 %

300 bar / 625 °C 640 °C 46,0 %

300 bar / 700 °C 720 °C 47,5 %

The current proven temperature level is just above 600 °C in steam temperatures and 46 % efficiency is attainable for conventional hard coal plants.

Other factors affecting to the plant overall efficiency are boiler efficiency and plant auxiliary power consumption.

The flue gas loss is the largest single item in the boiler efficiency. A temperature difference of around 20 °C in the exit flue gas temperature means one percent in the boiler efficiency and 0,4 % in the plant overall figure. Additional heat recovery systems in the flue gas systems have increased the boiler efficiency from typical 92 % to 95 %. Those systems in more details are presented in section “Boilers”. Regarding to combustion of wet fuels like lignite or brown coal the flue gas loss goes significantly up lowering the boiler efficiencies 1-2 percentage points. There is a lot of development work going on the drying of lignite before their combustion. That is also discussed more later in this report.

Typically 8-10 % of the gross generation is used by the plant auxiliaries. The boiler feed water pump drive being the largest single consumer. Large plants >300 MW have condensing steam turbine drives using reheat steam and discharging it into the main condenser or may have its own condenser. Those plants have electric motor driven



start-up pumps. One decisive fact to switch to steam turbine drive is as the unit size and steam pressure go up the power requirement of a boiler feed pump exceeds the available motor size (18-20 MW i.e. 500 MW and 270 bar or larger). The steam turbine concept reduces the plant auxiliary electrical power requirement to 4-5 %. A wet desulphurization plant typically adds 1,0-2 percentage points to the auxiliary power if necessary to apply.

It is also assumed that the cooling tower will be of natural draft type and there the required pumping head is low i.e. the distribution channels are only 10-12 metres above ground.

In Germany there has been a development project on a high efficiency 600 MW coal fired power plant by VGB, Power producers and power plant machinery manufacturers. It was called “North Rhine-Westphalia”. The concept was based on designs and materials currently available and tested in the actual operation. The plant has steam parameters of 285 bar/600°C/620°C. Recently several power plants have been contracted with similar steam parameters and those are targeting 46,0 % efficiency in hard coal firing.

Regarding lignite (brown coal) fired plants the targets are slightly less due to its moisture and ash contents:

Figure 1, Current efficiency trend in German large power plants firing lignite by Dr.Heithoff/RWE.



For the new TPP in Kosovo the following discounted benefits can be applied in the plant optimization what comes to its efficiency:

Kosovo New TPPEfficiency vs. Fuel & CO2 NPV

-400,0

-300,0

-200,0

-100,0

0,0

100,0

200,0

300,0

30 35 40 45 50

Efficiency %

Euro

per

kW

Fuel CO2-credit Combined

Figure 2, Efficiency vs. fuel and CO2 NPV

It has been calculated by using 1 EUR/GJ total fuel cost, 7500 hrs/a base load, 8 %/a discounting factor over 40 year life. The CO2-credit is assumed to be 20 EUR/ton. The graphical illustration states that the application of 20 EUR/ton carbon credit triples the value of the efficiency improvement i.e. 50 EUR/kW can be invested to improve the plant efficiency by one percentage point.

2.2 Materials for high temperatures

The following table summarizes the commonly applied materials for different service locations depending on the applied live steam pressure and temperature:



Table 1, Materials for high temperatures

Steam values HP Pressure (bar) 250 250 270 300 300 - 350 HP Temperature (oC) 540 566 580 600 650 - 720 IP Temperature (oC) 560 566 600 620 650 - 720

High temperature components

13 CRMo 44 HCM 2S HCM 12

Water wall panels

7 CrMoVTiB1010 T91, A617

X20 CrMoV 121

Final SH / RH outlet sections

T91, T92 Austenitic materials Ni-base alloy

NF616 / E911

Main pipes and boiler headers P91

P92 Ni-base alloy

Turbine parts and valve bodies 1 - 2 % Cr 9 - 12 % Cr Ni-base alloy

Today Future

It can be stated that the proven steam temperature for materials is just over 600 °C.

The following figure (by Hitachi Power) illustrates the materials and their impact on the efficiency:

Figure 3, Impact of steam parameters and materials on the plant overall efficiency



3 STEAM BOILERS

3.1 Lignite analysis The huge lignite resource found in Kosovo can be characterized with the following analysis as received from the Sibovc (>8000 samples analyzed) mine:

Heat value, LHV kJ/kg 8200 - range kJ/kg 6000-9500 Ash % 15,3 - range % 10-20 Moisture % 42 - range % 40-45 Sulphur, total % 1,1 - range % 0,7-1,5 Sulphur, combustible % 0,35 - range % 0,1-0,7 Carbon % 24,5 Hydrogen % 3,1 Nitrogen % 0,5 Chlorine % 0,00 Its typical ash analysis is as follows based on the analysis made during this study work: SiO2 % 31,0 Al2O3 % 14,5 Fe2O3 % 7,2 CaO % 17,0 MgO % 3,5

Others % 26,8 Grand total % 100,0 The typical ash melting temperature parameters are indicated to be based on the analysis made during this study work: Deformation °C 1220 Half ball °C 1260 Melting point °C 1270 This Kosovo lignite can be characterized by its relatively low ash content, low combustible sulphur as the most of the sulphur is found in sulphate/sulfite form and the existence of ample calcium in the fuel. The ash softening and melting temperatures are low and will cause problems in conventional pulverized combustion process if not properly considered at the design. The following figure illustrates different lignite fuels of the world (Hitachi Power):



Figure 4, Different lignite fuels of the world

The current studies to support new generation capacities has also a subproject on the existence of harmful elements in the Sibovc lignite like Na, K, Cl, F, Hg, Zn, Pb, Cd, Si, V etc. The detailed results are in a separate report Task 3.1.A. It can be stated that the corrosive elements (eg. chlorine) are fairly low and even mercury is at the detection level. The presence of limestone, CaCO3, in the fuel has been analyzed also during this study. The results indicate that the percentage of calcium oxide, CaO, in the ash varies between 6 and 45 %. The mole ratio Ca/S is more than 4 at the lowest CaO percentage for combustible sulphur i.e. the limestone in the fuel can absorb all the burnt sulphur into calcium sulphate provided that the combustion temperature is below 1000 °C. The average CaO percentage give Ca/S ratio >10. Emission requirements The new thermal power plant, TPP, will fully comply with the EU Large Combustion Plant, LCP, rules. That will mean the following emission levels from the beginning of the operation:

Sulphur dioxide, SO2 mg/nm3 200 Nitrogen oxides, NOx mg/nm3 200 Particulates mg/nm3 30

Applicable combustion methods and emissions The unit sizes considered for the new TPP are in a range of 300 to 500 MW net and that means heat release capacities in the range of 750-1250 MJ/s. For such a heat release capacity the following combustion methods can be considered:

Sibovc



Pulverized firing, PF or Circulating Fluidized Bed combustion, CFB

Regarding to the combustion products and the required emission levels into the atmosphere it appears that the CFB-combustion can meet the SO2- and NOx-emission limits straight from the combustion chamber without any additional flue gas cleaning measures. PF is able to meet the nitrogen dioxide emission by low-NOx-burners as the moisture in lignite maintains the temperatures sufficiently low in the furnace. However, PF would need separate flue gas treatment for reducing sulphur dioxide emissions to the required level as discussed below. Both combustion systems will need particulate removal to meet the allowable dust concentration in the exhaust. These combustion systems and the associated steam boilers are more discussed in the following section.

3.2 Pulverized fired boilers Traditionally pulverized firing has been used for large scale boilers. Pulverized firing means to process the fuel into fine powder that has mean particle size around 0,05 mm and the maximum size should not exceed 0,3 mm. That powder is injected into the furnace with preheated air and the ignition takes place by the radiation of the surrounding flame. The actual combustion lasts only few parts of a second. The hottest parts of the furnace are relatively close to the theoretical combustion of the used fuel i.e. with this wet lignite 1300-1400 °C temperatures can be expected. The heat flux to the furnace walls is intense in this burner zone and is one of the main design criteria for the furnace sizing. This high temperature means also that the ash particles may melt and become sticky as the ash melting temperature is equal or lower to the actual temperature in the flame.

The lignite fuel is delivered to the boiler silos pre-crushed i.e. the maximum size of the fuel is typically 30-40 mm. For pulverizing of wet lignite beater wheel pulverizers are most commonly used. There hot flue gases from the upper furnace are sucked for drying the wet fuel. The fuel is fed into the hot inlet duct and the drying fuel flue gas mixture passes trough the radial fan type pulverizer where the actual pulverizing takes place by centrifugal force as the fuel clumps collide against the fan enclosure wall made of abrasion resistant wear parts. The upper part of the pulverizer has a classifier that allows only fine particles to pass and coarse fraction is recycled back to the pulverizing process. The maximum capacity of a single pulverizer is approximately 150-200 t/h i.e. 500 MW unit needs three-five pulverizers depending on the fuel design basis (8200 or 6000 kJ/kg). In order to have continuous operating capability there has to be one spare pulverizer as they need periodic maintenance. The lignite in Kosovo, however, is relatively “soft” and the pulverizers can run 3000-4000 hours between their maintenance stops.

The following figure illustrates the pulverizer-burner arrangement in Kosovo B plant.



Figure 5, Pulverizer arrangement in Kosoco B (Stein/Alstom)

Ball mill type pulverizer would make more uniform fuel powder for combustion but it has been less used with voluminuous soft and wet lignites. The high hot flue gas flow is one of the limiting factors in this respect.

For large boilers tangential firing method is commonly applied and each pulverizer is feeding its own four burners i.e. one level at each wall and forming a swirl in the furnace by installing the burners inclined in the horizontal level. The burners fed by different pulverizers are in stacked form above each other. The burners are so called Low NOx-type where the combustion air is staged to reduce the absolute maximum temperatures in combustion thus effectively reducing the formation of thermal NOx.

Another burner arrangement is to locate them perpendicular on all the walls. In that case the burners are fixed and one pulverizer feeds one level. The furnace size and height for this capacity size, 750 – 1300 MW heat release is such that the residence time for the particles is 6-8 seconds and the exit gas temperature is around 1000 °C.

The air pre-heaters are normally of rotary type and due to the volume of flue gas stream there are two parallel units each designed for 50 % flow or the flue gas flow is split to have different heat recoveries for air preheating and steam water cycle (to be discussed later in this report).

The steam boiler itself is either built in tower form or as two-pass unit. The furnace and the boiler walls in the hot sections are of membrane construction welded gastight. Tower format saves space as the super, reheater and economizer heating surfaces are stacked above the furnace. The upper part of the boiler is typically split into two sections by a wall that is also acting as a heating surface. The flue gases after the economizer are leaving high up (>100-140 meters) and there has to be a duct to bring those flue gases down to the air pre-heaters. That duct is also an ideal location for placing a Selective Catalytic Reactor, SCR, for removal of nitrogen oxides whenever



it is required (not for Kosovar lignite). The flue gas temperature is there in the range of 400-350 °C and that is ideal for the operation of SCR.

A a boiler of two-pass configuration will need slightly more space in longitudinal direction than the tower boiler but the benefit is that the connecting external pipelines are slightly shorter.

Pulverized fired boilers are the largest conventional steam boiler units built today. Their maximum capacity is around 1300 MWe and steam parameters go up to 300 bar/600-620 °C.

The ash in fuel exits the furnace mostly in form of fly ash but a small fraction of the ash sticks onto the furnace walls and first heating surfaces. That slag is either removed by sootblowing (steam/air/water/acoustic) or just peeling off by its own weight. The slag is typically removed from the conical bottom through a wet slag drag chain conveyor. There might be a small grate type collection area before the actual conveyor for afterburning. The slag is cooled, crushed and transported by trucks/belt conveyors.

During recent years the following large brown coal / lignite fired plants have been built in Europe:

Plant Capacity MWe Year Boxberg 690 MW 2010

Neurath 2 x 1100 MW 2008 Niederaussem 1000 MW 2003

Boxberg 900 MW 2000 Regarding to the large lignite or brown coal fired boilers firing wet fuel the formation of the thermal nitrogen oxides is low due to the low actual combustion temperature in the furnace. If the nitrogen content of the fuel is low the large boilers can meet the requested EU/LCP-emission limit of 200 mg/nm3 with proper Low-NOx -burner design. The largest 800-1100 MW units can even go down to 150 mg/nm3 levels without any additional measures. The following figure illustrates the distribution of the steam parameters of large PF-boilers built or designed worldwide during the last years. It is worthwhile to recognize the volume of the Chinese PF-development: There are around 40.000 MW plants (600 MW units) with 255 bar/565 °C HP-steam parameters.



Figure 6, Distribution of supercritical steam parameters worldwide (Source HitachiPower)

3.3 Circulating Fluidized Bed combustion Fluidized bed combustion was initially developed for metallurgical purposes for roasting plants i.e. the combustible part of the feed material was removed and not to destroy/melt the base material which came out as ash. The combustion took place around 900 C. The partial introduction of combustion air underneath of the bed made it bubbling and that gave the name Fluidized Bubbling Bed, FBB. Gradually this bubbling bed technology was introduced for steam generation from high moisture content fuels as the bubbling bed offered ideal place for particles requiring long combustion time and the bubbling hot ash made the drying and ignition of wet fuel simple. In the 1970´s and early 1980´s the concept was attracting more and more interest by the boiler makers but a major obstacle was that full scale coal combustion was not possible as it created too high combustion temperature and the ash in the bed melted and then solidified.

It was recognized that by increasing the fluidizing air volume under the fluidizing grate the bed started to fly. Circulating Fluidized Bed, CFB, was born. In that concept the upward velocity in the furnace area is 4-6 meters and all the material follows with the flue gases up to a separator cyclone. There the heavy particles are separated and they are recycled back to the bed trough a loop seal/ash cooler. The clean flue gases leave the separator to the further heating surfaces. This concept made it possible to introduce necessary combustion air in stages at different levels of the furnace and maintain the combustion temperature at the prescribed 900-950 °C level even with dry



coals. It also made possible to utilize high ash fuels as the bubbling bed is easily choked by the high ash.

. Figure 7, Schematic diagram of CFB-boiler plant (Foster Wheeler)

It was also recognized that the combustion temperature of 850-950 °C is quite ideal for calcination of limestone to calcium oxide. Burnt CaO is capturing the sulphur of the fuel during its combustion process. The end product is a mixture of calcium sulphite, CaSO3 and inert calcium sulphate, CaSO4, in the ash and the sulphur dioxide emission is effectively reduced straight in the boiler. The desulphurization process is not as effective as in the separate flue gas desulphurization process. Compared with S-moles, typically 3 times more Ca-moles are required to reach 90 percent desulphurization degree vs. that of 1,0 for a downstream FGD. However, the process is simple and needs not any additional equipment except the pulverized limestone feeding into the furnace.

The low combustion temperature of CFB results also in low thermal NOx-formation as the emission almost exclusively comes from the nitrogen in the fuel.

In this particular case as the lignite contains a substantial amount of limestone, CaSO4 and the sulphur content of the fuel is low (Ca/S mole ratio >5) it can be expected that the sulphur dioxide emission will be extremely low i.e. a tenth of the allowable emission limit of 200 mg/nm3.

Typically the coal injected into furnace shall have an average particle size of 1 mm and the maximum lumps of 10 mm in diameter. There should not be more than 5 %



fine particles of 0,05 mm or less. Crushing of the fuel is normally executed outside of the boiler house at the fuel yard.

To start the operation the boiler needs sand to create the necessary inventory of the circulating hot inert mass for ignition. During its normal operation the fuel ash may be sufficient to maintain that inventory level. If the fuel ash is not able to upkeep the inventory level some (quarz) sand has to be added every now and then.

The fuel ash exits the boiler mostly (above 90 %) in the form of fly ash and the rest is taken out in dry form as bottom ash. If the fuel has a very high ash content (>30 %) special bubbling bed type ash coolers may be installed to remove and cool the excess bottom ash directly from the bed.

Structurally the most critical parts of a CFB-boiler are the fluidizing grate, separator/ hot cyclone and recycling system of the particles from the separator/hot cyclone. Those items can be briefly described:

The separator/hot cyclone has experienced substantial evolution during these 25 years. Initially it was made of heavy refractory as its operating temperature is around 900 °C. It was an independent uncooled structure outside the furnace. The thick refractory did not allow fast start-ups and many hot cyclone failures occurred. Erosion was also an issue. Gradually more experience has been gained in this respect. Nowadays there are designs where the separator is integrated into the furnace and its walls are water cooled membranes protected by a thin refractory. Some manufacturers (Alstom, Metso (previously AkerKvaerner), AEE) still use separate water or steam cooled cyclones even for large capacities. This type of design requires more space than the integrated approach. The expansion bellows between the furnace and the hot cyclone have also been the critical parts but sufficient design approaches have been developed to cope with the issue.

To recycle hot ash and fuel mixture from the hot cyclone back to the bed needs a control device “check valve” to prevent the fludizing air from disturbing this recycling process. Typically there is a seal pot that blocks the route and the flow to the right direction is controlled/assisted by small fludizing nozzles. Initially Lurgi, one of the main developers of the concept, placed some heating surfaces in the loop to cool the ash. Nowdays final superheaters can be located in this ash recycling loop (eg. Intrex by Foster Wheeler). The heat transfer is very effective from the hot ash directly to water/steam surfaces. Those heat surfaces are also protected from possible corrosive elements in the flue gases.

Regarding the maximum capacity of a CFB-boiler the development has been relatively fast: The first 100 MWe range utility type boilers firing coal were built in the late 1980´s and now there are several units in 250-300 MW range. The largest CFB in operation is hard coal fired 350 MW unit in Sulcis, Italy by Alstom. Foster Wheeler has built several units of 250 MW range burning wet brown coal (equal to Kosovo lignite) in Poland. All these boilers are designed for subcritical steam parameters i.e. 160-170 bar/540-565 °C with reheat.

There is one supercritical CFB-project under construction in Lagiza, Poland. Foster Wheeler will deliver 460 MWe CFB-boiler plant for 260 bar/580 °C/580°C steam parameters. The fuel is conventional bituminuous coal (<23 % moisture). The maximum sulphur content is 1,2 %. The design will apply new OTU straight tube concept. The plant is due to start early 2009.



To summarize the status of the CFB-development it can be stated that it is proven technology up to 350 MW with subcritical steam parameters.

3.4 Lignite drying Typically lignites contain 40-60 % moisture. That lowers considerably its heating value and increases the flue gas volume making the boilers much larger in size (more costly) than conventional hard coal fired ones. Additionally the increased flue gas flow pushes up the flue gas loss lowering the plant´s overall efficiency. The introduction of the cost of carbon dioxide emission has multiplied the cost of fuel and triggered search for more effective ways to utilize even low cost lignites.

An effective method to increase combustion temperature is to reduce the moisture content of the fuel as the illustration below shows.

Sibovc ligniteCombustion temperature vs. moisture in lignite

0

500

1000

1500

2000

2500

0 10 20 30 40 50

Water % in fuel

Max

imum

tem

pera

ture

C

Combustion temperature

Original lignite

Figure 8, Approximate maximum temperature in combustion vs. moisture content in lignite, combustion air preheating to 350 °C.

Another illustration gives idea on the impact of the moisture in lignite to the flue gas flow:



Sibovc Lignite 500 MW netFlue gas flow vs. Moisture

0

100

200

300

400

500

600

700

0 10 20 30 40 50Moisture %

nm3/

s

Flue gas flow

Sibovc

Figure 9, Flue gas volume vs. moisture in lignite for a 500 MW boiler plant

There are several methods to dry the lignite:

• Dryer –pulverizer: PF-boilers are using this type of pulverizers as described before. It has limited drying capacity as the drying gas is taken from the furnace and the in most cases the moisture enters the furnace. But the system brings the combustion temperature high enough for stable operation. Some dryer-pulverizers are able to separate the moisture and only the dry fuel is blown into the furnace.

• Steam – dryers: In Germany RWE and Vattenfall having large lignite and brown coal plants have extensively searched for drying concepts. Their aim is to improve the overall plant efficiency. Both are targeting to have 10-20 bar steam operated pressurized bubbling bed dryers to make dry lignite (<15 % moisture). The development projects are at large scale pilot plant phase (eg. RWE 200 t/h lignite). The following figures illustrate the dryer concepts considered.



Figure 10, Typical arrangement of lignite pre-dryer, heat pump may be replaced by LP-steam from/heat recovery from/to the turbine plant

The dried lignite changes the physical size of the furnace as the following illustration shows:

Figure 11, Comparison of the furnace arrangement with wet vs. dry lignite by courtesy of Hitachi Power (Neurath),



The dried lignite produces higher combustion temperature and that in turn makes the burner air distribution configuration more demanding in order not to have intensive fouling around the burners as the ash gets more fluid and the same applies to maintain nitrogen oxide formation under control. The following figure shows the situation with wet and dry fuel (upper line).

Figure 12, Typical combustion temperature with wet (green) and dry (brown) lignite (HitachiPower).

The dryer plant will need additional space aside of the boiler plant as the figure below shows:



Figure 13, Dryer plant arrangement

Anyhow the drying is still in the development phase worldwide and it will be commercially available sometime in the early 2010´s as the overall summary schedule sheet indicates:

Figure 14, Dryer technology development



Low temperature dryer: Great River 500 MW power plant in USA is testing a pilot plant using the cooling water from the plant condenser to heat two-stage bubbling bed dryer. The target is to reduce the moisture from 43 % to 35 %. The project is financed by DOE and its total value is around 30 million dollars.

Figure 15, Two stage fluidized bed lignite dryer using cooling water from the turbine condenser in Great River plant.

This kind of approach will not be applicable in Kosovo as its impact is marginal and apparently its cost will be extremely high compared with its benefits.

As a summary it can be stated that there are no commercially available any lignite drying system with proven references for this size of application (300-400 t/h wet fuel).



4 EMISSION CONTROLS The following paragraphs are a summary on the presentation to be found on the website of IEA (October 2005).

4.1 Desulphurization

Flue gas desulfurization can be classified into the following six main categories:

• wet scrubbers; • spray dry scrubbers; • sorbent injection processes; • dry scrubbers;

FGD units are widely installed in many countries as the emission requirements become stricter.

Wet scrubbers take the lead followed by spray dry scrubbers and sorbent injection systems in the FGD market throughout the world. Regenerable and combined SO2/NOx processes have a small share and the trend is not expected to change in the short-term according to current plans for new FGD installations. New developments in sorbent injection technologies are in progress and this type of FGD is expected to become more widely used in older coal-fired plants.

4.2 Wet scrubbers for SO2 control

Wet scrubbers are the most widely used FGD technology for SO2 control throughout the world. Calcium-, sodium- and ammonium-based sorbents have been used in a slurry mixture, which is injected into a specially designed vessel to react with the SO2 in the flue gas. The preferred sorbent in operating wet scrubbers is limestone followed by lime. These are favoured because of their availability and relative low cost. The overall chemical reaction, which occurs with a limestone or lime sorbent, can be expressed in a simple form as:

SO2 + CaCO3 = CaCO3 + CO2

In practice, air in the flue gas causes some oxidation and the final reaction product is a wet mixture of calcium sulphate and calcium sulphite (sludge). A forced oxidation step, in situ or ex situ (in the scrubber or in a separate reaction chamber) involving the injection of air produces the saleable by-product, gypsum, by the following reaction:

SO2 + CaCO3 + 1/2O2 + 2H2O = CaSO4.2H2O + CO2

Waste water treatment is required in wet scrubbing systems.



A variety of scrubber designs is available including:

• spray tower • plate tower • impingement scrubber • packed tower design • The fluidized packed tower

In the simplest configuration in wet lime/limestone/gypsum scrubbers, all chemical reactions takes place in a single integrated absorber resulting in reduced capital cost and energy consumption. The integrated single tower system requires less space thus making it easier to retrofit in existing plants. The absorber usually requires a rubber, stainless steel or nickel alloy lining as construction material to control corrosion and abrasion. Fibreglass scrubbers are also in operation. Commercial wet scrubbing systems are available in many variations and proprietary designs. Systems currently in operation include:

• lime/limestone/sludge wet scrubbers; • lime/limestone/gypsum wet scrubbers; • wet lime, fly ash scrubbers; and • other (including seawater, ammonia, caustic soda, sodium carbonate,

potassium and magnesium hydroxide) wet scrubbers.

Wet scrubbers can achieve removal efficiencies as high as 99%. Wet scrubbers producing gypsum will overtake all other FGD technologies, especially with the increased cost of land filling in Europe and the introduction of increasingly stricter regulations regarding by-product disposal.

Figure 16 presents the process.



Figure 16, Wet scrubber SO2 removal process / “Wet gypsum process” (Scholven)

A wet desulphurization process needs a considerable amount of auxiliary power and that typically adds 1,0-2,0 %-points to the auxiliary power figure. If a conventional stack is used to discharge the flue gases they have to be reheated after the process up to 100 °C by a rotary preheater taking its heat from the flue gases entering the desulphurization process. In a case where the flue gases are taken into an evaporative cooling tower the flue gases can be taken directly without any preheating.

4.3 Spray dry scrubbers for SO2 control

Spray dry scrubbers require the use of an efficient particulate control device such as an ESP or fabric filter. A recycling facility would improve sorbent utilisation and disposal of the by-product is the norm. The sorbent usually used is lime or calcium oxide. The lime slurry, also called lime milk, is atomised/sprayed into a reactor vessel in a cloud of fine droplets. Water is evaporated by the heat of the flue gas. The residence time (about 10 seconds) in the reactor is sufficient to allow for the SO2 and the other acid gases such as SO3 and HCl to react simultaneously with the hydrated lime to form a dry mixture of calcium sulphate/sulphite. Waste water treatment is not required in spray dry scrubbers because the water is completely evaporated in the spray dry absorber. The by-product also contains unreacted lime which may be recycled and mixed with fresh lime slurry to enhance sorbent utilisation as not all of the lime reacts with the SO2. Factors affecting the absorption chemistry include flue gas temperature, SO2 concentration in the flue gas and the size of the atomised or sprayed slurry droplets.

The absorber construction material is usually carbon steel making the process less expensive in capital costs compared with wet scrubbers. However, the necessary use of lime in the process increases its operational costs.

Spray dry scrubbers are the second most widely used FGD technology. However, their application is limited to flue gas volume from about 200 MWe plants on average. Larger plants require the use of several modules to deal with the total flue gas flow. This is why in general the technology is used in small to medium sized coal-fired power plants. Spray dry scrubbers in commercial use have achieved removal efficiency in excess of 90% with some suppliers giving >95% SO2 removal efficiency as achievable.



Figure 17, Process diagram for Spray dry scrubber based SO2 control

4.4 Sorbent injection systems for SO2 control

Sorbent injection systems can be divided into four types. These are:

• furnace sorbent injection; • economiser sorbent injection; • duct sorbent injection; and • hybrid sorbent injection.

The simplest technology is furnace sorbent injection where a dry sorbent is injected into the upper part of the furnace to react with the SO2 in the flue gas. The finely grained sorbent is distributed quickly and evenly over the entire cross section in the upper part of the furnace in a location where the temperature is in the range of 750-1,250°C. Commercially available limestone (CaCO3) or hydrated lime (Ca(OH)2) is used as sorbent. Whilst the flue gases flow through the convective pass, where the temperature remains above 750°C, the sorbent reacts with SO2 and O2 to form CaSO4. This is later captured in a fabric filter or ESP together with unused sorbent and fly ash.

Removal efficiency of up to 50 % can be obtained with a Ca/S ratio of 2 with Ca(OH)2 used as sorbent. If CaCO3 is used as sorbent the removal efficiency will be considerably lower, or the Ca/S ratio will have to be much higher.

In an economiser sorbent injection process, hydrated lime is injected into the flue gas stream near the economiser zone where the temperature is in the range of 300-650 °C.

In duct sorbent injection, the aim is to distribute the sorbent evenly in the flue gas duct after the preheater where the temperature is about 150 °C. At the same time, the flue



gas is humidified with water if necessary. Reaction with the SO2 in the flue gas occurs in the ductwork and the by-product is captured in a downstream filter. Removal efficiency is greater than with furnace sorbent injection systems. An 80 % SO2 removal efficiency has been reported in actual commercial installations.

The hybrid sorbent injection process is usually a combination of the furnace and duct sorbent injection systems aiming to achieve higher sorbent utilisation and greater SO2 removal. Various types of post furnace treatments are practised in hybrid systems, such as:

• injection of second sorbents such as sodium compounds into the duct; and • humidification in a specially designed vessel.

Humidification reactivates the unreacted CaO and can boost SO2 removal efficiency up to 90 % depending on the process. The hybrid process offers the following advantages:

• relatively high SO2 removal; • low capital and operating costs; • easy to retrofit; • easy operation and maintenance with no slurry handling; • reduced installation area requirements due to compact equipment; and • no waste water treatment.

4.5 Dry scrubbers for SO2 control

Circulating fluid bed and moving bed technologies, which utilise a dry sorbent to reduce SO2 emissions in a flue gas stream in a dedicated reaction chamber are categorised as dry scrubbers.

In the circulating fluid bed (CFB) dry scrubber process, hydrated lime is injected directly in the CFB reactor. Water is also injected into the bed to obtain an operation close to the adiabatic saturation temperature. The process achieves SO2 removal efficiency of 93-97% at a Ca/S molar ratio of 1.2-1.5. Flue gas enters the CFB reactor at the bottom, then flows vertically upwards through a venturi section and enters an upper cylindrical vessel. The height of the vessel is designed to accommodate the mass of bed-material required to achieve the desired residence time of about three seconds. All external inputs of re-circulating material, fresh sorbent and gas humidifying water are introduced to the gas on the diverging wall of the ventur. The process is easy to maintain and operate because it does not require high-maintenance mechanical equipment such as abrasion resistant slurry pumps, water atomisers or sludge dewatering devices. The process can achieve >95% SO2 removal efficiency.

In the moving bed dry scrubber, a dry absorbent made of coal ash and lime is injected into the absorber. There is currently one plant using this technology and achieving 90% SO2 removal efficiency.



4.6 Regenerable processes for SO2 control

In regenerable processes, the sorbent is regenerated chemically or thermally and re-used. Elemental sulphur or sulphuric acid is recovered from the SO2 removed. The revenue from these by-products can compensate partially for the higher capital costs required in such FGD systems. Although these processes can achieve high SO2 removal efficiencies (>95%) they have in general high capital costs and power consumption.

4.7 Flue gas discharge –stack vs. cooling tower The last large coal/lignite fired new units have been using cooling tower to discharge the flue gases. Combined with the moist air (water vapour is less dense than dry air) the hot flue gases form a huge single warm air mass and goes upwards more than the hot flue gases would do from the stack. The polluting fractions are especially in case of an evaporative cooling tower the plume of the flue gases is mixed with moist air of the tower. The combined uplifting effect doubles the effective stack height and thus lowers significantly the pollutant levels at ground level around the plant.

In case of pulverized firing there will be with a high probability wet flue gas desulphurization (FGD) plant discharging saturated flue gases at 60-70 °C. With this arrangement there is no need for reheating of those flue gases to eliminate visible plume from the stack and to keep the stack walls dry. The elimination of the cooling/reheating heat exchangers lowers the cost of the FGD plant.

The introduction of the flue gases into the cooling tower does not change the main dimensions of the tower as the flue gas flow is just a minor fraction of the cooling air flow. The tower upper internal surface may have a special coating against the flue gases.

The concept lowers the total cost of the plant as the separate stack with its heavy foundations can be completely eliminated.

The following figure illustrates the arrangement of the flue gas ducts in a dry cooling tower (the cocept is exactly the same also in evaporative towers where the ducts terminate 20-30 meters above the cooling water distribution level).



Figure 18, Flue gas discharge through a (dry) cooling tower (by Heller)



5 STEAM TURBINES

Main parameters guiding the steam turbine construction are:

• Admission steam parameters • Reheat steam parameters • Cold end optimisation • Manufacturers proven design

These factors define the selection of steam turbine construction materials, number of casings and turbine process thermal efficiency potential.

The investment cost develops in steps following the changes in the materials, number of turbine casings, and size of the casing. Turbine casings and shafts are standard components that are designed for limited process parameters while the steam path is tailored for each case with different types and sizes of blades.

The turbine process efficiency follows partly linearly the raising steam parameters and partly in steps by the number of feed heating stages i.e. feed water end temperature and selection of LP last stage blade length and number of steam turbine casings.

5.1 Material selection In general the steam inlet parameters define the turbine material selection. The steam admission pressure mainly effect to the pressure casing construction while the temperature affects to material selection. It shall though be understood that the steam admission parameters are always an optimised pair where benefit of one parameter depend on the other. Increasing only pressure does not improve the efficiency unless the temperatures follow with the pressure and visa versa.

In the unit size in question (300-500 MW range) the turbine high pressure steam path from steam admission to cold reheat - and intermediate steam path from hot reheat to the low pressure casing inlet may be in one integrated HP/IP casing or in two separate casings. The main key factor in the casing construction is the HP-steam parameters – mainly pressure.

In case of conventional pressures – that is drum boiler pressures up to <170 bar - the most common solution is one combined HP/IP casing while supercritical steam parameters usually require separate high pressure and intermediate pressure casings.

Separate or common HP and IP casings is turbine manufacturers´ strategic decisions and some vendors have chosen the construction where there are always separate casings for the main steam admission and hot reheat steam.

The expansion in the turbine steam path with the properly selected HP-steam parameters and one reheat passes far above the erosion-corrosion area (today known better as FAC = Flow Assisted Corrosion). Also the cooling tower cold end mean relatively warm cooling water and the exhaust steam moisture content remain relatively low (7…10 % moisture).



Erosion-corrosion does not affect to the LP-steam path and casing material selection, but though LP turbine exhaust moisture is moderate it is still proposed that protection measures against last turbine stage water drop erosion are applied. Such measures are mechanical moisture removal through grooves in the last LP guide vanes and flame hardening of the last rotating stages. Last rotating stages of Titanium are expensive solution, but are also durable against water drop erosion. The cold end optimisation may also result one casing LP turbine with longest LP last stages – which are usually of titanium - because of the better strength/weight ratio. Using of titanium is though not necessity and shall be left to the turbine manufacturer’s decision. The following figures illustrate the impact of Titanium in the last blades in large turbines. The unit is 1100 MW and it is made with two LP-sections. For a 500 MW unit one section would be enough.

Figure 19, 1100 MW turbine by Alstom with Titanium last stage.

Another method to reduce the costs is to arrange the exhaust from the LP-sections sidewise and install the condenser at the same level as the turbine. An estimate is that this arrangement lowers the height of the turbine house by 12 meters but on the other side its width is increased by the condensers.

5.2 Steam turbine High pressure and Intermediate pressure casings

300 MW size range 300 MW unit size is still a little bit small to fully utilize supercritical steam parameters. The main factor is steam volumetric flow at the HP-steam path first stages. The steam volumetric flow is so small that the turbine blade length is relatively small and the tip and root losses decrease the expansion efficiency from supercritical pressures to conventional pressure. Benefit from more advanced steam parameters are



partly eliminated by the losses due too small volumetric flow. Nevertheless supercritical steam parameters are not here exclude as an alternative, but the benefit of such steam parameters are marginal.

CFB technology does not have yet operating references other than drum boiler type units. This mean moderate steam parameters meaning pressures <170 bar and temperatures optimal to this main steam pressure level (< 560 oC).

Considering both the unit size and combustion technology it seem obvious that the 300MW unit will be with sub-critical type main steam parameters being 165 – 200 bar 545-560 oC and intermediate (reheat) steam pressures 35-45 bar 545-560 oC.

500 MW Units or larger The HP-steam flow does support the utilizing of supercritical steam parameters. There start to be references of very high steam parameters and main steam parameters can be raised up to 260-275 bar and temperatures up to 600/600 oC.

In steam turbine the 600 oC temperature requests more high grade materials than conventional 540-560 °C temperatures. In case of welded rotor construction the steam admission part and first stages could preferably be of more heat resistant material though this is an advantage of the construction and not necessity.

The supercritical steam parameters mean definitely separate High pressure and Intermediate pressure casings as basic solution.

5.3 Number of LP turbine casings

300 MW unit size: Number of the low pressure casings depends on unit size and turbine process cold side optimisation. In 300 MW units only one LP casing solution is quite probable. The key issue is the electricity valuation price and steam turbine vendor standard LP casing exhausts areas. Most vendors though have large enough LP last stage blades to handle the 300 MW units with only one two flow LP casing.

500 MW unit size: In 500 MW units only one LP casing solution is quite possible though optimal solution may also be two LP casing solution. The key issue is the electricity valuation price and steam turbine vendor standard LP casing exhausts areas. Most vendors though have large enough LP last stage blades (Titanium) to handle the 500 MW units with only one double-flow LP casing but this will request increased exhaust pressure and large losses in the cold end.

5.4 Turbine condenser A cooling tower has been selected as the plant’s main cooling system. As is enough water available the tower type will be wet cooling tower. In wet cooling tower – like in once through cooling – the shell and tube type main condenser is basically the only solution. Shell and tube type vacuum condenser is also in general the most commonly used condenser type.



In the shell and tube surface condenser the steam is exhausted from the turbine LP section into the condenser steam chamber through which the cooling water pipes are routed in tube bundles. Steam is condensed on cooling water tube outer surfaces and the condensed water is removed by gravity force downwards to the bottom of the condenser corpus where the condensate hotwell is located. The system is proven and reliable and well adapted to various load cases from back-pressure load to full condensing load. It is easy to adopt the bypass steam supply to this type of condenser.

The number of cooling water flows determines the number of independent flows into which the cooling water supply is divided in the condenser. Each flow will then consist of a large number of cooling water tubes.

Main condenser ought to have at least two flows. Each shall be such that it may be separated from the water side for cleaning or plugging of leaking cooling water tube.

5.4.1 Material Selection The main condenser surfaces are in contact with ambient air (shell), main cooling water (tubes and water chambers) and circulating steam/water (tubes, shell and hotwell). The chemical composition of these elements is decisive for the selection of materials to be used.

Condenser tubes The main cooling water will come from the wet cooling tower. The composition of cooling water is decisive when selecting main condenser tubes. In general, the material properties of the compared tube material with assumed cooling water quality may be simplified as follows: General

Corrosion (2)

Pitting in Running

Water

Pitting in Stagnant

Water

Pitting / Stress Corr.

Erosion Corr. (WTR side)

Water Drop

erosion

Stainless steel (*) +++ ++ ++ ++ +++ +++

Copper based + + + + + +

Titanium +++ +++ +++ +++ ++ +++ (*) Grade AISI 316L or better +++ Best resistance in comparison to the other two alternatives + Lowest resistance in comparison to the other two alternatives

Stainless steel (SS) tubes have in general better resistance against corrosion than copper-based materials. Also, SS resistance against water drop erosion is better than copper alloy’s.

Titanium has very good properties and good references but it is not used here because its price is very high and because of the high grade stainless steel has sufficiently good mechanical properties and is significantly cheaper at the same time.



As the chlorine content of the main cooling water is estimated to reach values of 90 .. 140 ppm, the SS tube material AISI 316L will be considered. Ordinary stainless steel, AISI 304, should not be used if the chlorine content of the cooling water exceeds 70 ppm.

5.5 Generator The maximum reliable and proven size of the air cooled generators has been increasing continuously. Most generator manufacturers have expanded their line of air cooled generators close to or above the 300 MW unit size.

Also the efficiency of the air cooled generator have been increasing so that in the 300 MW unit size the most efficient air cooled generators have closely the same efficiency as the hydrogen cooled generators have in general. As there is no hydrogen system and thereby no sealing oil systems etc. the operational costs of the air cooled generators are lower than the hydrogen cooled generators.

Based on the marginal efficiency difference and higher operation costs the air cooled generator is more probable solution in the 300 MW unit sizes.

Due the lack of references of air cooled generators in the 500MW size class hydrogen cooled generator remain only alternative in the 500 MW units. Some generator manufacturers may even propose water cooling for the stator.



6 IGCC (INTEGRATED GASIFICATION COMBINED CYCLE)

6.1 Background

The basic IGCC process consists of the following functions; gasifying coal to produce synthetic gas (syngas), burning the gas in a power producing gas turbine and using the hot exhaust gas from the gas turbine to produce power in a steam water cycle process. Thus the IGCC process is basically a combination of two well known processes,

1) coal gasification process and 2) gas fired combined cycle power plant process.

The gas fired combined cycle process is commonly used in natural gas fired power plants in utility and industrial power plants. The characteristics of the process are high power production efficiency and low NOx emissions compared to the Rankin cycle (steam) process. The coal gasification has been known for a long time now. The first larger coal gasification applications were implemented already during the Second World War in Germany to produce transportation fuel. But the process has not made an actual break through in normal market conditions because of the relatively high investment cost of the gasification process and good availability of Oil and Natural Gas throughout the world. Integrated coal gasification combined cycle process development started in the US during the first oil crisis in the 1970’s. The development and demonstration projects were resulted with three 120 MW class IGCC plants by 1987. The primary driver for starting to develop and build IGCC plants was the potential of combining the benefits of having a cheap and abundant domestic fuel (coal) to the efficiency of the combined cycle process. At the same time low cost natural gas supply grew fast and natural gas fired combined cycle plants that did not require any investments to a gasification plants offered a more attractive solution at the time and were built extensively. On the other hand the pressure to shift from the Rankin cycle process to IGCC in coal based power production decreased as critical and supercritical steam values were applied in the Rankine cycle process increasing its power production efficiency to the same level that had been achieved with IGCC (over 43 %). More recently IGCC has been discussed again as it offers lower cost for CO2 capture than the Rankin cycle process and also because it still has potential for achieving higher efficiency than the Rankin Cycle process even if it has not been achieved yet. The following paragraphs are mostly based on the recently published report “An Overview of Coal based Integrated Gasification Combined Cycle (IGCC) Technology by MIT (LFE 2005-002 WP) and Gas Turbine World February 2007 edition.

6.2 Process description Figure 20 shows the main blocks of a coal based IGCC plant. The coal is supplied to the gasifier where it is partially oxidized under pressure (30-80 bar). The plant uses



oxygen as oxidant and therefore has an air separation unit (ASU). In the gasifier, which is of the entrained flow slagging type, the temperature may exceed 1500 °C. The high temperature ensures that the ash is converted to a liquid slag with low viscosity, so that it may easily flow out of the gasifier.

Figure 20, IGCC process without CO2 capture In addition to its chemical energy (heating value), the hot raw syngas contains sensible heat which may be recovered in heat exchangers to produce steam for the steam turbine. In the gas clean up process, particles, sulphur and other impurities are removed. At this point, CO2 may also be captured. Because of the high partial pressures of the species and the low volume flow of syngas, the gas clean up process is very efficient and low cost compared to traditional flue gas cleaning. The clean syngas is then fed to the gas turbine for generation of electricity. Gas turbines for syngas operation are commercially available. Compared to natural gas operation, some minor modifications in combustors and operating conditions are required. The gas turbine may also be integrated in two different ways with the ASU. If not conflicting gas turbine operation characteristics, any excess nitrogen from the ASU should always be utilized by the gas turbine for NOx reduction and increased power generation. Most of the sensible heat in the hot gas turbine exhaust gas is recovered in the heat recovery steam generator (HRSG) which supplies the steam to a turbine for additional electricity production. The separation between different IGCC processes is based on the differences between gasification technologies and whether CO2 is captured or not.

6.3 Classification of gasifiers A number of gasifier technologies have been developed to various extents, and they may be classified as shown in Table 1 below. Operating temperature for the different gasifiers is to a large extent dictated by the ash properties of the coal. Depending on



the gasifier, it is desirable either to remove the ash dry at lower temperatures (non-slagging gasifiers) or as a low viscosity liquid at high temperatures (slagging gasifiers). For all gasifiers it is essential to avoid that soft ash particles stick to process equipment and terminate operation.

Table 2. Characteristics of different gasifier types// source: C. Higman and M. van der Burgt, “Gasification”, Elsevier, 2003

Gasifier type Fixed bed Fluidized bed Entrained flow Outlet temperature

Low (425-600 °C) Moderate (900-1050 °C)

High (1250-1600 °C)

Oxidant demand Low Moderate High Ash conditions Dry ash or slagging Dry ash or

agglomerating Slagging

Size of coal feed 6-50 mm 6-10 mm < 100 µm Acceptability of fines

Limited Good Unlimited

Other characteristics

Methane, tars and oils present in syngas

Low carbon conversion

Pure syngas, high carbon conversion

Fluidized bed gasifiers are less developed than the two other gasifier types. Operating flexibility is more limited for this class of gasifiers because of performing several functions (e.g. fluidization, gasification, sulfur removal by limestone injection) at the same time, and there are too few independent variables for the desired process optimization. Still the fluidized bed technology perhaps offers better potential for utilizing low rank coals with high ash and moisture content. The four major commercial gasification technologies are (in order of decreasing capacity installed):

1. Sasol-Lurgi Dry Ash 2. GE (originally developed by Texaco) 3. Shell 4. ConocoPhillips E-gas (originally developed by Dow)

6.4 Performance without CO2 capture

6.4.1 Efficiency Electrical efficiencies around 40 % (LHV) have been achieved in existing commercial scale demonstration plants. Because the power block of an IGCC plant is similar to that of a natural gas combined cycle (NGCC) plant, the efficiency of the latter is a natural reference for the IGCC plant. Currently, NGCC efficiencies are approaching 60 % (LHV). The efficiency penalty of an IGCC compared to an NGCC is mainly explained by effects in the gasification process. In order to reach the slagging temperatures, the fuel is partially combusted which means that chemical energy is converted into heat. The ratio of the chemical energy in the product syngas and the chemical energy in the coal feed (LHV cold gas efficiency) is typically around 0.7–0.8. Depending on configuration, some of the produced heat may or may not be recovered. Either way, a significant efficiency penalty or energy loss arises



because heat is a lower quality energy form than chemical energy. Furthermore, the production of the oxygen for gasification requires auxiliary compression work. In addition to these major points, current IGCC gas turbines may be less efficient because of restrictions in turbine firing temperatures. Several factors influence the efficiency: + Coal type: Coals of high rank can be gasified more efficiently than coals of low

rank. The higher moisture and ash content of low rank coals require a higher degree of oxidation (more oxygen) to achieve slagging temperatures because of the energy needed to vaporize the moisture and melt the ash. Most recent studies have focused on high rank coals.

+ Gasification technology: Gasifiers with a dry feed are more efficient than gasifiers with a slurry feed because less water must be vaporized. Gasifier technologies which include syngas coolers for heat recovery of the sensible heat of the hot gas, are more efficient than those with a water quench.

+ Degree of ASU integration: Integration of the air separation unit with the gas turbine increases the electrical efficiency. By supplying part or all of the ASU air from the GT compressor outlet, less efficient compression in a separate compressor is reduced or avoided.

+ Technology level: Gas turbine technology and turbine inlet temperature will together with the choice of steam cycle have a significant impact on electrical efficiency.

While the three first bullets addresses the efficiency gap between an IGCC and an NGCC, the last bullet points to the fact that improvements in combined cycle technology will also benefit the IGCC. A review of recent studies of IGCC plants indicates efficiencies in the range 38.0-47.4 % (LHV). The wide range is explained by the above factors.

Availability The risk of low IGCC availability is still an issue. Figure 2 shows the history of availabilities for the demonstration IGCC plants. It can be seen that most of the plants were able to reach the 70-80 % range after a number of years. However, by adding a spare gasifier, it seems likely that IGCCs can provide availabilities equivalent to that of NGCCs. At the Eastman Chemicals plant the gasifier has been 98 % onstream over a three year period. According to Bechtel, a next IGCC plant should be able to achieve around 85 % availability without back-up fuel or a spare gasifier.



Figure 21, IGCC availability history (excluding operation on back-up fuel). Graph provided by Jeff Phillips, EPRI

Environmental performance An inherent advantage of the IGCC process is the potential for low emissions by using fuel gas clean up – instead of flue gas clean up. Because of the high partial pressures, impurities can be removed more effectively and economically compared to conventional clean up of the large volume flow of the combustion flue gas.

Table 3

Pollutant/ Environmental issue

Performance

SO2 Commercial processes such as MDEA and Selexol can remove more than 97 % of the sulfur so that the clean syngas has a concentration of sulfur compounds < 20 ppmv. The more expensive Rectisol process can similarly achieve a concentration of < 0.1 ppmv. SO2 emissions of 68 g/MWh has been demonstrated at the ELCOGAS plant in Puertollano, Spain

NOx The emissions are similar to those of a natural gas fired combined cycle plant. Dilution of syngas with nitrogen and water are used to reduce flame temperatures and lower thermal NOx

formation to levels < 15 ppm

4 . Further reduction to single digit levels are

possible with selective catalytic reduction (SCR), but have some disadvantages such as ammonia slip, increased requirement for sulfur removal and reduced power output.



Mercury Commercial technology for mercury removal is available. 99.9 % removal from syngas has been demonstrated. The cost of Mercury removal has been estimated to $ 7 522/ kg for IGCC vs. $ 83 333/ kg for PC plants.

Other emissions

Emission of CO is caused mainly by incomplete combustion in the gas turbine. Permit levels are typically 15 ppm. VOC5

emissions also result from incomplete combustion, and compliance with permit levels is normally done by calibrating VOC emissions to CO emissions. PM6 includes solid charcoal and slag particles and liquid drops from cooling tower operation.

Trace elements

A large number of the periodic table is present in coals in trace amounts, and currently there is an incomplete understanding of how these trace elements partition between the slag, fly ash, syngas and gas clean up streams.

Solid wastes IGCC produces about half the amount compared to conventional PC plants. The solid waste is also less likely to leach toxic metals which are encased in the solidified slag [30]. The slag is a useful by product with a value.

Water use IGCC use 20 % - 50 % less water than conventional coal plants. The reason is that the steam cycle represents a smaller part of power generated.

4Short for ppmvd@15% (parts per million dry at 15 % O2) 5Volatile organic compounds

6Particulate matter

Key IGCC technology issues

Gasifiers The range of choices in gasifier technology may be represented by the slurry feed GE gasifier with a water quench and no heat recovery versus the dry feed Shell gasifier with syngas coolers. This results in the GE gasifier having lower costs, but also lower efficiencies. For high rank coal (bituminous coal), studies conclude that the slurry feed GE quench gasifier has lowest capital cost for plants without and with CO2 capture. For low rank coals such as lignite, less data are available, but the Shell gasifier seems to be the lower cost option.



Table 4, Effect of coal type on E-gas IGCC systems. Adapted from Table 5 Effect of coal type on E-gas IGCC systems. Adapted from

Coal type Pittsb. #8 Illinois #6 PRB Lignite Heatin value, Btu/lb (HHV ar) 13100 11000 8200 7500 Ash %, dry basis 7.5 12.5 17 20 Slurry conc. (% dry solids) 66 63 56 50 Relative feed rate 1 1.25 1.8 2 Number of gasifiers 2 2 3 4 Relative heat rate, Btu/kWh HHV (Base 3830) 1.00 1.06 1.14 1.22 Relative capital cost, (per kW) 1.00 1.09 1.24 1.39 For an IGCC based on the slurry feed E-gas gasifier, shows that both the efficiency (heat rate) and the capital cost is affected significantly by the increased moisture and ash content of the lower rank coals such as lignite. Although data are not available for the less efficient GE gasifier, it seems likely that the negative impact of coal rank would be similar or worse. A study by the Canadian Clean Power Coalition indicated that the dry feed Shell gasifier was the more economical than slurry feed E-gas and GE gasifiers for an IGCC with CO2

capture. If this is the case, the Shell gasifier would also be more economical for a plant without capture. This latter point is explained by the higher penalty of Shell IGCCs for CO2

capture.

Table 5 Effect of coal type on E-gas IGCC systems. Adapted from

Coal type Pittsb. #8 Illinois #6 PRB Lignite Heatin value, Btu/lb (HHV ar) 13100 11000 8200 7500 Ash %, dry basis 7.5 12.5 17 20 Slurry conc. (% dry solids) 66 63 56 50

Relative feed rate 1 1.25 1.8 2 Number of gasifiers 2 2 3 4 Relative heat rate, Btu/kWh HHV (Base 3830) 1.00 1.06 1.14 1.22 Relative capital cost, (per kW) 1.00 1.09 1.24 1.39



Gas turbines Gas turbines need only minor modifications to use syngas as fuel and are available from manufacturers like GE and Siemens. There are some effects of using syngas as fuel which influences the gas turbine performance. Because of the low heating value of syngas, more mass flow of fuel is supplied to achieve a certain limiting turbine inlet temperature. In addition nitrogen from the ASU and syngas saturation contribute to higher mass flow through the turbine and more power output. Compared with the natural gas as fuel, depending on syngas composition, there may be a higher fraction of water vapor in the gas turbine exhaust. This will increase heat transfer and put more strain on materials, and it will be required to decrease the turbine inlet temperature to maintain design material life. This reduction means a lower efficiency for the power block.

Maturity Experience with coal based IGCC plants on commercial scale exist from a few demonstration projects with government support .

Table 6 Commercial scale coal/petcoke based IGCC demonstration plants

Project participant/ Plant name

Location Electric output (net)

Gasifier type

(current owner)

Gas turbine

Dates of operatio

n

Southern California Edison/ Cool Water

Barstow, CA 100 MW GE with heat recovery GE 7E 1984 -

1988

Dow (Destec)/LGTI

Plaquemine, LA 160 MW ConocoPhilli

ps E-gas

Siemens SGT6-3000E

1987 - 1995

Nuon/ Nuon Power Buggenum

Buggenum, The

Netherlands 253 MW Shell

Siemens SGT5-2000E

1994 - present

Destec and PSI Energy/ Wabash River

West Terre Haute, IN 262 MW ConocoPhilli

ps E-gas GE 7FA 1995 - present

Tampa Electric Company/ Polk Power Station

Mulberry, FL 250 MW GE with heat recovery GE 7 FA 1996 -

present

Elcogas/ Puertollano

Puertollano, Spain 298 MW Prenflo

Siemens SGT5-4000F

1998 - present

Sierra Pacific Power Company/Pinon Pine

Reno, NV 99 MW KRW air

blown fluidized bed

GE 6FA

1998 – 2000 (18 start-up

attempts,



failed to achieve steady state

operation)

In 2004, several commercial alliances formed to offer IGCC customers “one stop shopping” in the future. GE purchased ChevronTexaco’s gasification business and announced cooperation with Bechtel. ConocoPhillips announced a similar alliance with Fluor. Also, Black & Veatch joined Uhde for execution of Shell gasification projects in the US. All the components needed in an IGCC plant are commercially available. Several demonstration projects based commercial gasifiers have been carried out and they have shown that problems have occurred – but also that they have been manageable.

Performance with CO2capture

When considering capture of CO2

in the IGCC design, two additional process blocks are needed (besides the compression of CO2

for transportation): + A shift reactor in which the CO reacts with H2O to H2 and CO2

+ An absorption process for capture using the Selexol process or other

processes based on physical solvents, or an MDEA process based on chemical solvents

In the shift reactor, the heating value of the CO is transferred to H2

and the carbon atoms end up in the CO2

molecules. It has been found that a so called sour shift upstream the sulfur removal. The reduction in electrical efficiency for a plant with CO2 capture is explained by the following factors:

+ Exothermic shift reaction produces heat from syngas fuel and required coal feed rate to provide necessary rate of chemical fuel energy to the gas turbine increases. The produced heat is less efficiently converted to electricity than chemical energy (fuel heating value).

+ If steam/carbon ratio is to low (as for Shell gasifiers), steam must be supplied from the steam cycle and is equivalent to an electricity production loss

+ CO2 compression work

If a chemical solvent such as MDEA has been used (as opposed to a physical Selexol solvent), there is also a significant energy loss for regeneration of the solvent. Restrictions on the firing temperature of current gas turbines will also result in an efficiency reduction. For example, one study showed that the efficiency penalty (LHV) for a case with the GE gasifier was 6.5 %-points (from 38.0 % to 31.5 %), and 8.6 %-points (from 43.1 % to 34.5 %) for the Shell case. Most processes required for CO2capture from IGCCs have been demonstrated at commercial scale. For example, commercial chemical plants for production of



ammonia require hydrogen and therefore include a shift reaction and separation of CO2. An advanced gas turbine (F class or higher) has not been demonstrated on near 100 % hydrogen fuel. However, for an IGCC application which involves an air separation unit, there is no reason to combust a pure hydrogen stream in the turbine, rather it is beneficial to dilute with nitrogen to reduce NOx

emissions and increase power output. Current GE guarantees involve fuel specifications, which limit maximum CO2

capture to around 85 %. According to Norman Shilling, GE these limitations are related to the current fuel supply system and does not represent a major challenge to modify. A fuel mixture of 50 % H2

and 50 % N2 by volume would

be an acceptable fuel and would therefore impose no limitation on CO2capture. The following table summarizes the current performance status of most commonly used gasifiers either without CO2-capture or with that:

Table 7, Current view of the performance of different gasifiers in IGCC-plants without or with CO2-capture (DOE, 2007)

It has to be noted that the efficiency is stated in high heating value, HHV, instead of the low one, LHV. The “European way” to express efficiency in LHV will improve the figures above approximately by 2 percentage points. Anyhow the CO2-capture has a remarkable impact on the plant efficiency. The following figure gives an idea on the investment costs for different power generation modes without/with CO2-capture. It has to be noted that there IGCC is based on dry hard coal and a lignite plant would be some 40 % more expensive.



Figure 22, Inital cost of different power generation forms

6.5 Conclusions The current gasifier capacity (operating and planned) is distributed as follows by feedstocks and endusers:

Figure 23, Gasification by feedstock (DOE, 2007)



Figure 24, Gasification by endues (DOE, 2007)

It has to be noted that power generation still today only accounts some 15 % of the total gasification capacity. The total installed capacity is 4000 MW. In order to compete with pulverized coal plants or CFB coal plants, the major challenges for new large IGCCs will be to demonstrate higher availabilities and lower capital costs. The capital cost compared to a CFB plant is especially high in a case where low rank coal such as the Kosovo lignite is used. Thus unless the IGCC investment costs drops dramatically and higher availabilities are realized the only feasibility argument for favoring IGCC over conventional steam cycle based power generation is the easier and cheaper capture of CO2. However so far in most cases the CO2 capturing option does not offer any advantage as there is no use for the CO2 and the capturing and storing cost (€ 40-60 per ton) is well above the cost of purchasing CO2 emission rights (€ ~20 per ton).



7 CO2 - CAPTURE

Few remarks can be made on carbon dioxide capture as that may come imperative or the acquisition cost of its emission rights may justify inclusion of the process. To handle the whole chain of CO2-capture means:

• capture of carbon dioxide from fuel/combustion products

• transport CO2 and

• store it in stable method

It can be summarized in the following figure:

Figure 25, Chain of CO2- capture

This short review just concentrates on the first item how to separate the carbon dioxide from the fuel and its combustion products. That appears to be the most costly item in the chain:

Transportation

Pipelines

Ships

Motor carriers

Railway

CO2 Capture

Power plants

Gasprocessing

Reformer and gasificationplants

Storage/ Market

Enhanced oil/gas recovery

Enhanced coal bed methane production

Storage in saline aquifers

Ocean

Carbonation

Chain reaction of CO2-capture, it is not capture it has to be transported and stored!



80

515

Approximation of cost distribution to capture, transport and storage

Storage

Transport

Capture

– CO2 capture has been identified as the most costly part of the CO2removal chain

– CO2 capture has the least well established technology compared to CO2 transportation and storage technologies

Figure 26, Typical cost distribution of CO2-capture chain

There are several methods to capture CO2 in the power generation processes and the following diagram illustrates three potential paths in this respect:

Figure 27, Potential methods for CO2-capture in power generation

Postcombustion means that the separation takes place from the flue gases after the actual power generation process (conventional steam plant)

Oxyfuel means that the combustion takes place with pure oxygen/oxygen enriched air which makes the separation process more compact

Pre-combustion

Oxyfuel

Post-combustion

Fossil Fuel Combustion

CO shiftGasification/Reforming

Combustion

ASU

CO2 separation

CO2storage

CO2 separation

CO2separation

Power generation

Flue gases

O2

Power generation

Syngas (H2 + CO)

Power generation

H2 rich fuelH2 + CO2

CO2 + H2O



Pre-combustion where fuel is gasified/reformed and CO2 separated in an early phase of the process to make hydrogen rich fuel.

The flue gases containing CO2 can be treated either by

• absorbent/sorbent

• membrane

• gryogenic in order to separate CO2 from other components of the gas stream. Today there are several quite proven technologies applying chemical absorbents (amines).

The possible CO2-capture plant applying absorbent process will need considerable space aside of the power plant. The actual flue gas treatment facility is few scrubbing towers between the electrostatic precipitators /FGD plant and the stack/cooling tower. But the regeneration plant for the chemicals will occupy large area. One estimate is that some 12.000 m2 is required for a 500 MW unit. The regeneration plant will need low pressure steam from the turbine plant i.e. it would be natural to locate the regeneration facility aside of the boilerhouse. The following figure illustrates the required space for 500 MW unist:

Figure 28, Approximate space requirement of CO2-capture facility for 500 MW units

200 m

400 m



It has to be recognized that the technology is still in the development phase but large utilities are seriously looking at the issue and some like Vattenfall in Germany is going to build a small 30 MWth pilot plant at its Schwarze Pumpe power plant. It should be operational by 2008 at a total cost of 57 million EUR. The captured CO2 will be stored in the adjacent rock formations. Vattenfall is predicting to have its commercial concept available sometime 2015-2020. The pilot plant is based on oxyfuel-concept as the following diagram shows:

Figure 29, Vattenfall pilot plant for CO2-capture at Schwarze Pumpe

November, 2007


Contract nr 122521/D/SER/KOS



Task 3.2. A&B

Carbon Market Study

Studies to support the development of new generation capacities and related transmission Page 2 (26) Task 3.2.A&B, Carbon Market study November, 2007


Disclaimer




CONTENTS

1 CARBON MARKET REVIEW.......................................................................................... 4

1.1 The United Nation Framework Convention on Climate Change (UNFCCC)................ 4 1.2 Main agreements concerning CO2 emissions ................................................................ 4 1.3 The “Flexibility Mechanisms”........................................................................................ 5 1.4 Emissions Trading .......................................................................................................... 6

1.4.1 Definition ................................................................................................................ 6 1.4.2 Main trading systems and market price................................................................... 6 1.4.3 Main rules................................................................................................................ 8

1.5 Clean Development Mechanism (CDM)........................................................................ 8 1.5.1 Definition ................................................................................................................ 8 1.5.2 Main rules................................................................................................................ 8 1.5.3 CDM’s Project Phases............................................................................................. 8 1. Planning of the Project ................................................................................................... 8 1.5.4 CDMs Advantages & Disadvantages .................................................................... 10

1.6 Joint Implementation (JI).............................................................................................. 10 1.6.1 Definitions............................................................................................................. 10 1.6.2 JIs Project phases .................................................................................................. 10 1.6.3 Main rules.............................................................................................................. 12 1.6.4 JIs Advantages & Disadvantages .......................................................................... 12

1.7 Land Use, Land Use Change and Forestry ................................................................... 12 1.8 Flexible Mechanism restraints...................................................................................... 13 1.9 Monitoring, Reporting and Review.............................................................................. 13 1.10 The Voluntary Carbon Market.................................................................................. 14

2 KOSOVO SITUATION..................................................................................................... 16

2.1 Baseline situation.......................................................................................................... 16 2.2 Scenario 1 ..................................................................................................................... 18 2.3 Scenario 2 ..................................................................................................................... 18 2.4 Scenario 3 ..................................................................................................................... 22 2.5 Scenarios evaluation ..................................................................................................... 24

3 CONCLUSIONS ................................................................................................................ 26



1 CARBON MARKET REVIEW

The purpose of this chapter is to review the evolution of the Carbon Market since it was introduced and to describe the mechanisms that can be applied to the Project of the new Power Plant in Kosovo. The most relevant issues concerning the carbon market will be recalled and summarised in order to develop some sustainable alternatives that could be undertaken in the context of the Project.

1.1 The United Nation Framework Convention on Climate Change (UNFCCC) The Convention on Climate Change (UNFCCC) entered into force on 21 March 1994. Its main purpose is to set an overall framework for intergovernmental efforts to tackle the challenge posed by climate change. It recognises that the climate system is a shared resource whose stability can be affected by industrial and other emissions of carbon dioxide and other greenhouse gases. At the moment the Convention enjoys near universal membership, with 173 countries having ratified. Under the Convention, governments are expected to:

gather and share information on greenhouse gas emissions, national policies and best practices

launch national strategies for addressing greenhouse gas emissions and adapting to expected impacts, including the provision of financial and technological support to developing countries

cooperate in preparing for adaptation to the impacts of climate change

1.2 Main agreements concerning CO2 emissions It took all of one year for the member countries of the Framework Convention on Climate Change to decide that the Convention had to be augmented by an agreement with stricter demands for reducing greenhouse-gas emissions. By 1995 governments had begun negotiations on a protocol, an international agreement linked to the existing treaty, but standing on its own. The text of the Kyoto Protocol was adopted unanimously in 1997 and it entered into force on 16 February 2005. The Protocol's major feature is that it has mandatory targets on greenhouse-gas emissions for the world's leading economies that have accepted it (ANNEX I Countries). In particular, it is possible to define three possible positions towards the Kyoto Protocol:

Annex I Countries: they have accepted it and have been assigned an emission cap Non-Annex Countries: they have accepted it but they haven’t been assigned an

emission cap Other Countries

The mandatory targets for Annex I Countries range from -8 per cent to +10 per cent of the countries’ individual 1990 emissions levels "with a view to reducing their overall emissions of such gases by at least 5 per cent below existing 1990 levels in the commitment period 2008 to 2012."



In almost all cases, even those set at +10 per cent of 1990 levels, the limits call for significant reductions in currently projected emissions. Future mandatory targets are expected to be established for "commitment periods" after 2012. These are to be negotiated well in advance of the periods concerned. Commitments under the Protocol vary from nation to nation. The overall 5 per cent target for developed countries is to be met through cuts (from 1990 levels) of 8 per cent in the European Union (EU[15]), Switzerland, and most Central and East European states; 6 per cent in Canada; 7 per cent in the United States (although the US has since withdrawn its support for the Protocol); and 6 per cent in Hungary, Japan, and Poland. New Zealand, Russia, and Ukraine are to stabilise their emissions, while Norway may increase emissions by up to 1 per cent, Australia by up to 8 per cent (subsequently withdrew its support for the Protocol), and Iceland by 10 per cent. The EU has made its own internal burden sharing agreement to meet its 8 per cent target by distributing different rates to its member states. These targets range from a 28 per cent reduction by Luxembourg and 21 per cent cuts by Denmark and Germany to a 25 per cent increase by Greece and a 27 per cent increase by Portugal. The Kyoto Protocol offers flexibility in how countries may meet their targets. For example, they may partially compensate for their emissions by increasing "sinks" (forests, which remove carbon dioxide from the atmosphere). That may be accomplished either on their own territories or in other countries. Or they may pay for foreign projects that result in greenhouse-gas cuts. Several mechanisms have been set up for this purpose, as shown in the following paragraph. After the collapse of climate change negotiations in The Hague, Netherlands, in November of 2000, many thought the Kyoto Protocol was doomed to fail. However, eight months later in Bonn, Germany, countries were able to pick up the pieces and resume negotiations with renewed momentum. The Bonn negotiations resulted in a political agreement that set forth broad-brush guidelines on key issues including the flexible mechanisms, "sinks," funding, and compliance. The Seventh Conference of the Parties (COP7) to the UNFCCC, held in Marrakech, Morocco, in October of 2001 was tasked with finalising the underlying legal texts for the Bonn Agreement and setting in place the accounting system for the Kyoto Protocol. This task was completed and the finalised texts are all contained in the 245-page Marrakech Accords.

1.3 The “Flexibility Mechanisms” The Kyoto Protocol defined three innovative “flexibility mechanisms” to lower the overall costs of achieving its emissions targets. These mechanisms enable Parties to access cost-effective opportunities to reduce emissions or to remove carbon from the atmosphere in other countries. In fact, while the cost of limiting emissions varies considerably from region to region, the benefit for the atmosphere is the same, wherever the action is taken. The three market-based mechanisms that are intended to increase flexibility in meeting emissions targets are Emissions Trading, Joint Implementation (JI), and the Clean Development Mechanism (CDM). The Bonn agreement set out some big picture



guidelines enthuse mechanisms: for example, Annex I countries may make wide use of the mechanisms (until the 50% of their target), but they may not use JI or CDM credits generated by nuclear power to meet their targets and, in the first commitment period of 2008-2012, they may only include CDM "sinks" credits up to 1 percent of their assigned amount. In Bonn, Parties also established a fast-track process for specific categories of small-scale projects. A number of additional key issues regarding the mechanisms were decided in Marrakech. The eligibility requirements for participation in the mechanisms were among the most contentious issues in Marrakech. In order to participate, a country must:

be a Party to the Protocol have satisfactorily established its assigned amount have in place its national system for estimating emissions and removals have in place its national registry; have submitted its most recent required inventory (the inventory must also be

assessed for quality); submit the supplementary information required to show that it is in compliance with

its emissions commitments. For Parties that have failed to meet the eligibility requirements, expedited procedures were adopted to reinstate their eligibility if they are able to demonstrate that problems have been resolved. In the following paragraphs a brief description of the Flexibility mechanisms is presented.

1.4 Emissions Trading 1.4.1 Definition

Emissions trading (or cap and trade) is an administrative approach used to control pollution by providing economic incentives for achieving reductions in the emissions of pollutants. This mechanism, as set out in Article 17 of the Kyoto Protocol, allows Annex I Parties to acquire units from other Annex I Parties and use them in order to meet their emissions targets. This enables Parties to make use of lower cost opportunities to reduce emissions. Emissions trading schemes may be also be established as climate policy instruments at national levels (e.g. in the United Kingdom) and regional levels (e.g. in the European Union). Under such schemes, governments set emissions obligations to be reached by the participating entities. Depending on the rules of the scheme, these obligations may be fulfilled through holding either the ERUs, CERs, AAUs and RMUs established under the Kyoto Protocol or other units established specifically within those trading schemes.

1.4.2 Main trading systems and market price

The main trading system of the carbon market are the ones that follow:

EU ETS THE NEW SOUTH WALES



UK ETS CHICAGO CLIMATE EXCHANGE

Within these trading systems, the most relevant part of the total exchange volumes and values is realised at the moment in the EU ETS, while the other systems, contributing for few points percentage, are still to be considered under development.

Fig.1 – EUAs Spot Market Price (Source: www.co2prices.eu)

Referring to the Allowance’s value of only the EU ETS, called EUAs, in Figure 1 the spot market price development from March 2005 (ETS into force) to May 2007 is presented. From the graph it is possible to identify two different periods. The first, before April 2006, has been characterised by an average spot price of about 22 €/tCO2. The variability of the price in this period is mainly due to the fact that EUA prices are closely correlated with both oil and gas prices and weather. For example, a cold, dry winter as Europe experienced, spiked demand for both heat in Europe and reduced generation from hydroelectric sources. This encouraged coal generators to run their plants at higher capacity during peak hours, making them “short” EUAs, and increasing the demand – and price of EUAs. The end of this first period is signed by the drastic collapse of the price of the end of April 2006, representing the response to the publication of the verified emission data for 2005. Actually it was publicly reported that the Czech Republic, Estonia, France, the Netherlands, Spain and the Walloon region of Belgium had made announcements showing their position was longer or less short than expected. On the whole, the surplus from these regions adds up to 50 MtCO2 (which is in the range of the shortfall that had been expected in the market for 2005). After this drop and the following increase during the month of May, the price started decreasing progressively, reaching very low levels, even below 1 €/tCO2 at the beginning of 2007. At the moment the spot price is near its minimum value, around 0,3 €/tCO2.



1.4.3 Main rules A central authority (usually a government agency) sets a limit or cap on the amount of a

pollutant that can be emitted. Companies or other groups that emit the pollutant are given credits, which represent the right to emit a specific amount. The total amount of credits cannot exceed the cap, limiting total emissions to that level. Companies that pollute beyond their allowances must buy credits from those who pollute less than their allowances or face heavily penalties. This transfer is referred to as a trade. In effect, the buyer is being fined for polluting, while the seller is being rewarded for having reduced emissions. Thus companies that can easily reduce emissions will do so and those for which it is harder will buy credits which reduces greenhouse gasses at the lowest possible cost to society.

While the cap is usually set by a political process, individual companies are free to

choose how or if they will reduce their emissions. In theory, firms will choose the least-cost way to comply with the pollution regulation, creating incentives that reduce the cost of achieving a pollution reduction goal

1.5 Clean Development Mechanism (CDM) 1.5.1 Definition

CDM, introduced by the 12th article of Kyoto Protocol, allow ANNEX I Countries to obtain emission credits generated by projects for the reductions of emissions developed in NON-ANNEX Countries.

CDM has the purpose of sustaining NON-ANNEX Countries in reaching a sustainable development.

1.5.2 Main rules

A CDM Project is effective only if it imply a measurable and a real reduction of Greenhouse Gases, in comparison with the emission level that would be achieved without the Project (Baseline).

The Beneficiary Country must have ratified the Protocol The use of Nuclear Energy is not allowed in a CDM Project The ANNEX I Country that proposes the Project receives Certified Emission Reduction

Credits (CER’s) on the basis of the difference between the CO2 emission of the Baseline and the ones generated by the Project itself. Such Credits can be used to reach the target of reduction of the proposing county or they can be sold on the Emission Trading Market.

The beneficiary country has to confirm if the CDM Project reaches his target.

1.5.3 CDM’s Project Phases A CDM Project is generally composed by the following phases: 1. Planning of the Project 2. Project Design Documents 3. Approval 4. Validation 5. Registration



6. Monitoring 7. Verification During the development of these phases different subjects are implied, like shown in Fig.2. During the pre-feasibility phase, in which the planning of the Project is undertaken, the Project Developer prepares a Project Idea Note (PIN), a brief description (about 5 pages) of the main characteristics of the Project, like its typology, localisation, reduction foreseen, financial structure, CER’s price and social and economical advantages. The governments of the countries involved define a Designated National Authority (DNA), in order to approve the decision of the countries involved to take part in the Project. After the Host Country preliminary approval, the Project developer must prepare the Project Design Documents (PDD) and then forwarded to the Designated Operational entity (DOE) that will validate the activities. A Project Design Document is generally composed by:

• General description of the activities: title, technical description and main purposes of the Project, subjects involved, localisation, forecast of the CO2 reduction, description of the financial sources.

• Baseline methodology application: Description of the baseline methodology (in relation with the ones approved by UNFCCC). The baseline for a CDM Project activity is the scenario that reasonably represents the anthropogenic emissions by sources of greenhouse gases that would occur in the absence of the proposed Project activity.

• Verification of Additionality: A CDM Project activity is additional if anthropogenic emissions of greenhouse gases by sources are reduced below those that would have occurred in the absence of the registered CDM Project activity. CDM executive board has developed a “tool” which provides a general framework for demonstrating and assessing additionality. While it is not mandatory for Project proponents to use the tool, and they may also propose other tools for the demonstration of additionality, in reality, many Project proponents tend to utilise the tool in order to be approved by the CDM-EB.

• Timeline of the activities (crediting period): The crediting period is defined as the period in which the greenhouse gases emissions reduction can generate CER’s credits. The crediting period can last 7 years, with possibility of extension till 21 years, or 10 years without extension.

• Monitoring plan: It contains all the specification on the data that must be monitored, with description of the methodology that will be used.

• Greenhouse gases emissions calculation: It contains the CO2 emissions forecasted for the Project, including the ones related to the Project implementation.

• Environmental impact: it can be requested by the beneficiary country • Comments of the subjects involved.

After the DOE validation of the PDD documents, the Executive Board makes the formal approval of the Project. During the Operation phase, all the data and methodologies used in order to monitor the emissions reduction are described by the Project developer. The certification is made by



the Designated Operational Entity that, after receiving and analysing the monitoring report, calculates the emission reductions of the Project. Then it supplies a Verification report to the subjects involved and to the Executive Board that, after the Certification, distributes the CER’s credits.

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Fig. 2 – CDMs Project Scheme (Source: Pöyry) 1.5.4 CDMs Advantages & Disadvantages

• For the proposing Counties: The proposing Country can reduce emissions with lower cost than the ones that would be necessary if operating at a national or local level. On the other hand it has to sustain the costs of transaction of the Project, such as cost for developing the Project’s documents, the monitoring plan, the validation procedures, and all costs implied with the Credits (registrations, selling procedures etc..).

• For the beneficiary Country: CDMs attract ANNEX I countries to develop businesses and implementations of high efficiency technologies within the emerging countries. CDMs are expected to generate investment in developing countries, especially from the private sector, and promote the transfer of environmentally friendly technologies in that direction. On the contrary, CDMs may increment the economical and technological dependence by industrialised countries.

1.6 Joint Implementation (JI) 1.6.1 Definitions

• JI, introduced by the 6th article of Kyoto Protocol, allow ANNEX I Countries to develop projects for the reductions of emissions in others ANNEX I Countries.

1.6.2 JIs Project phases

The development of a JI Project follows different tracks in relation of the characteristics of the Country that host the Project, as described here below:



Track 1: If the Host Country satisfy the eligible criteria, it shall select the Project,

verify the emission reductions and release the correspondent amount of ERUs. In this case the Project follows a simplified track.

Track 2: It is applied when the Host Country doesn’t satisfy the eligible criteria. In

this case the procedure is similar to the one of the CDMs Projects, and the track is longer and more difficult.

Like CDMs, JIS Projects are usually developed in phases: 1. Project Planning: 2. Project Approval 3. Determination of the Project 4. Activities Monitoring 5. Emission reductions determination 6. ERUs emissions

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Fig. 3 – JIs Project Scheme (Source: Pöyry)

These phases imply the involvement of different subjects, like shown in Fig.3. Besides, the distinction between Track 1 and Track 2 procedure causes huge differences in the development of the phases of the Project. For what concern the pre-feasibility and feasibility phases, the Project Planning is based upon the Project Idea Note (PIN), which is followed by the Letter of Endorsement of the Host Country. In the case of Track 2, after the PIN, the Project Developer must also provide the Project Design Documents (PDD), that must be verified by the Independent Entity (IE).



For what concern the Project Determination, while in the case of Track 1 it is held by the countries involved, in the case of Track 2 it is developed by an Independent Entity, accredited among the Supervisory Committee, that shall provide a review and an approval of the choice. The last steps of the development phase is the Registration of the Project as JI Project by the Host Country, and the following Letter of Approval. Within the Operational phase, the Monitoring procedures are undertaken by the Project developer that, in the case of Track 1, simply collects the emission reduction in the specific registries. In the case of Track 2 the Project Developer has to follow the procedures described in the monitoring plane presented in the PDD. For what concern the determination of the reductions, while for Track 1 it is made by the Countries involved themselves, for Track 2 an Independent Entity has to calculate and verify the values. Finally, for both Tracks, after the approvals, the guest Country can release the correspondent ERUs amount.

1.6.3 Main rules

• The difference between the quantity of greenhouse gases emitted and the one that would have been emitted in absence of the Project (baseline) generates some Emissions Reduction Units (ERUs).

• The JI projects are characterised by the fact that the Emission Reduction Units related by the Project generate a decrease of the Assigned Amount Units (AAUs) of the beneficiary country, for a lump sum that is zero.

• Projects starting as of the year 2000 may be eligible as JI projects if they meet the relevant requirements, but ERUs may only be issued for a crediting period starting after the beginning of the year 2008.

• In order to implement a JI, the countries involved must have ratified Kyoto Protocol and they must belong to ANNEX I. Moreover, for both the proposing Country and the guest one, the presence of the AAUs national registry is requested.

1.6.4 JIs Advantages & Disadvantages

• The ERUs generated by the Project can be used to succeed in reaching the country targets, or can be sold on the Emission Trading Market.

• The investor can reduce emissions with lower cost than the ones that would be necessary if operating at a national or local level.

• The beneficiary country generally receives high efficiency technologies.

1.7 Land Use, Land Use Change and Forestry The Bonn Agreement allows countries to meet part of their targets through four types of land use, land use change and forestry (LULUCF) activities: forest management, cropland management, grazing land management, and re-vegetation. These activities, commonly referred to as "sinks" activities, absorb carbon from the atmosphere and fix it in plants, soil and other organic matter. Each Annex I country was allocated a number of tons of carbon uptake that it could count towards its emissions target from forest management activities. If cropland, rangeland or re-vegetation activities are selected, they must be accounted for on a "net-net" basis (rate of uptake during the commitment period minus rate of uptake in 1990).



Each Annex I country must provide information on its sinks activities in a separate report that establishes its assigned amount, including such issues as how it will define "forest," the geographical location of these activities, and how and when it intends to account for them (either annually or at the end of the commitment period). Annex I countries must also report on their national "legislative arrangements and administrative procedures" for ensuring that these activities contribute to the conservation of biodiversity and sustainable use of natural resources.

1.8 Flexible Mechanism restraints Parties made some important decisions regarding tradable emissions units. Annex I countries will be allowed to bank from one commitment period to the next any assigned amount units (AAUs) that they do not need for meeting their target. Banking of emissions reduction units (ERUs) and certified emissions reductions (CERs) generated under JI and the CDM, respectively, is limited to 2.5 percent of a Party's initial assigned amount, a generous limit that few are likely to reach. Each Party will be required to retain emissions units in a commitment period reserve (CPR) of an amount equal to 90% of its allowable emissions or five times its most recently reviewed emissions inventory, whichever is lower. The CPR was designed to address the risk of overselling. A new unit was created for sinks credits generated in Annex I countries. These units, referred to as removal units or RMUs, must be used in the commitment period in which they are generated and cannot be banked for future commitment periods. However, this limitation is of little practical consequence because CERs, AAUs, ERUs, and RMUs are, with a few exceptions, interchangeable. Consistent with the Bonn Agreement, the Marrakech Accords limit sinks projects in the CDM to afforestation and reforestation. Conservation projects are explicitly excluded. In the first commitment period, Annex I Parties' use of CERs from such projects is limited to an amount equal to 1 percent of their assigned amount.

1.9 Monitoring, Reporting and Review The Marrakech Accords outline how a country must calculate and record its annual emissions. Utilizing best practice standards from the Intergovernmental Panel on Climate Change (IPCC), each country's national system should ensure that the quality of "carbon credits" entering the market will be sound. Adjustments will be made in cases where countries have underestimated their emissions. As mentioned above, in cases where the inventories are poor, the country will not be allowed to enter the carbon market. The Marrakech Accords include an international accounting system to keep track of all the carbon credits bought and sold and calculate whether a country has met its target at the end of the commitment period. The accounting system will include a transaction log administered by the Kyoto Protocol secretariat that will record all issuances, transfers, acquisitions, cancellations and retirements of AAUs, ERUs, CERs and RMUs. The system will be very transparent and includes:

serial numbers for each carbon unit the country where the credit was initiated



the type of unit; the type of Project (if it is derived from a Project)

This is an essential step that allows governments and civil society to track how countries and companies meet their obligations. The log will also automatically check to ensure that: each party is eligible to use the mechanisms, there are no infringements of the CPR, there are no infringements of the sinks caps and there are no unresolved discrepancies. If a discrepancy is flagged, Parties have 30 days to take corrective action. The Accords also create a system of review by expert review teams (ERTs). ERT members will be selected by the secretariat based on their expertise, but also giving consideration to geographical balance. The ERTs will review annual inventories (including information on sinks activities), information on assigned amounts, national systems for monitoring emissions and removals, national registries, and at the insistence of OPEC countries, information on minimization of adverse impacts of response measures on developing countries.

1.10 The Voluntary Carbon Market In parallel with the regulatory mechanisms previously described, in the last years a voluntary market for carbon offsets has emerged. The voluntary market of carbon offsets refers to entities (companies, governments, NGOs, individuals) that purchase carbon credits for purposes other than meeting regulatory targets. These voluntary offsets are often bought from retailers or organizations that invest in a portfolio of offset projects and sell slices of the resulting emissions reductions to customers in relatively small quantities. While CDMs and JIs projects generate CERs and ERUs, credits generated by projects held within the voluntary market are called VERs (Verified emission reductions).

Fig. 4 – Retail Market Scheme

The Voluntary Carbon Market represents the main part of the Retail Market, which refers to companies and organizations that invest in offset projects and then sell off portions of the emission reductions in relatively small quantities with a mark-up. The offset projects can be either CDMs or Non- CDMs, and so they can generate either CERs or VERS. Fig.4 shows the main differences between these two kind of credits. While both of them



are sold on the Retail Market, only CERs can be used to meet a regulatory target. Above the Retail market, a survey indicated that almost 95% of the emission reductions were VERs, with CERs and ERUs comprising just 5%. The retail market is currently quite small, but it is growing rapidly. Several service providers have reported a doubling of sales each year for the past two years. By the way the evaluation of its size is not so easy. Even if both the World Bank and Ecosystem Marketplace maintain databases of non-CDM project transactions, they are largely incomplete due to the small and fragmented nature of the retail market and to the lack of any centralized registration for non-CDM projects. For what concern the VERs prices, they vary enormously, from US$5 - $35 or more per tCO2e, depending on the quality and location of the project and the mark-up imposed by the provider. Beside market evaluations, one main difference between projects that generate VERS and the CDMs projects is that for the firsts it is not necessary to follow an approval procedure as long and expensive. These procedures have often penalized small scale projects, even if recently the CDM Executive Board has adopted special rules to encourage small-scale CDM projects, involving lower registration fees and simplified documentation and auditing procedures. In order to give to a project the ability of generating VERs, generally the majority of retail providers adopt self-developed standards and verification procedures, rather than following the CDM and Gold Standard guidelines. Self-developed standards are difficult to judge because they can either be quite weak or even more stringent than the established standards. The Voluntary Market buyers are generally business and industrial firms, non-profit organisations, governments and individuals, motivated by different reasons in buying voluntary offsets. For firms, several factors have contributed to this increase in interest. First, there has been a rise in Environmental reporting, which has raised awareness among the general public and business community. The increasing prominence of the corporate social responsibility agenda has led to more firms becoming concerned about sustainability and the projection of a responsible image to the public. Many large firms will include an analysis of their climate impact and mitigation strategies in their annual sustainability reports or in the CSR section of their web sites. In general, for firms, even without regulatory constraints, demonstrating a commitment to reducing carbon emissions and purchasing offsets is a way to boost their ‘green’ image as an environmentally responsible company. Moreover non-profit and charitable organisations are a natural market for voluntary offsets with sustainable development benefits and various governments, eager to demonstrate their responsibility, have been developing plans to purchase carbon offsets, particularly for air travel. In general, buying into voluntary offsets is essentially about taking ‘personal responsibility’ for the impact of one’s actions on the climate. One of the main weaknesses of the Voluntary market is its credibility. The lack of internationally accepted standards for voluntary offsets makes very difficult for potential buyers to assess the credibility and quality of various providers and projects. Increased availability of information on who the providers are and what types of projects are available would be of use to buyers and would help the growth of this market even more.



2 KOSOVO SITUATION

Taking into account the general framework described in the previous paragraph, the aim of this chapter is to analyse the possible scenarios that could arise within the Kosovo situation in the next years, concerning CO2 emission.

2.1 Baseline situation In order to forecast the evolution of the Country in relation with this topic, it is necessary to define a baseline situation, from which the emission reduction or increment will be calculated. The baseline situation takes into account the results of Task 1, in which both the actual situation and the one foreseen for the next years are outlined. Here below the main characteristics, taken as starting points, are summarised. • Position toward Kyoto Protocol: At the moment Kosovo does not belong to the

ANNEX I Countries and it has not even ratified the Kyoto Protocol. • Generation Grid: As described in Task 1, the electricity system of Kosovo is mainly

supplied by the Kosovo A and Kosovo B thermal power plant. Besides their installed capacity is 800 MW and 678 MW respectively, at the moment Kosovo A and Kosovo B can provide just 280 and 554 MW, due to the fact that during the nineties these plants, Kosovo A in particular, have been exploited without any maintenance. Of the almost 4000 GWh produced in 2006, about 900 GWh are produced by Kosovo A, about 3000 GWh are produced by Kosovo B and the remaining 100 GWh are produced by Hydro. As shown in Task 1, the energy balance of 2006 shows that while a great amount of energy (2720 GWh) is imported, almost the same amount (2420 GWh) is exported. Being the energy that is imported mainly energy that transits across the Country, it will not be taken into account in the energy balances. For the years preceding 2030, the assumptions made in paragraph 1.1.1.3.2 concerning the operation plans for Kosovo A and Kosovo B have been considered for the calculations. Figure 2 resumes the main assumptions regarding both the retirements of the existing power plants and the entering into force of the new units.



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Fig.2 – Thermal Power Plants total Capacity

• Load forecast: For what concern the load forecast for the next years, the main results of Task 1 have been taken into consideration. For instance, the medium growth scenario curve has been considered. For such curve, represented in Fig.3, the total demand (comprehensive of the losses) almost reaches 14000 GWh/year in 2060.

Load Forecast - Medium Growth Scenario

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Starting from the actual situation, here above resumed, different scenarios of development have been evaluated. The main element of variability, that distinguishes the different scenarios, is the position of Kosovo toward the Kyoto Protocol. In particular, the first Scenario analyses the development in the case Kosovo would not ratify Kyoto (actual situation), the second Scenario presents the results that could emerge if Kyoto would ratify Kyoto, but without any emission limitations. Finally, the third Scenario describes the possible development that would occur if Kosovo became part of the Annex I Countries. Within each scenario, the main consequences due to the Project implementation will be presented and commented.

2.2 Scenario 1 In this Scenario Kosovo doesn’t ratify Kyoto Protocol. The country will not have any emission limit and moreover it won’t be possible to implement any of the flexibility mechanism presented before, neither if a Annex I country would propose it. In this context the CO2 emission level could be completely ignored because it would not have any economical or legal implication. By the way, emission reductions eventually generated by the Projects could produce carbon credits within the Voluntary Market, as described in Par. 1.10. Since there are no standard procedures to be taken as a guideline, the effective amount of reductions (and the corresponding amount of VERs) is not univocally determined. Supposing that the emission reductions are the same as the ones generated following a CDMs procedure (see Scenario 2 below), besides their price, a relevant issue will be the credibility that will be given to these amounts, in order to attract buyers and Retail Providers.

2.3 Scenario 2 The basic assumption of this scenario is that Kosovo will ratify the Kyoto Protocol in the next years, but it won’t have any CO2 emission cap. With this hypothesis Kosovo will not be an Annex I Country, and therefore it will not have any emission limit. The absence of having an emission cap would avoid, from the Kosovo point of view, any generation Project to take into account the Carbon Market and the related CO2 price. From this point of view, the choice of the technology to be implemented will be based upon economical and technical consideration, and probably also environmental considerations will be held, but without giving to the CO2 emission amount an economic value. For what concern the flexibility mechanisms implementation, in this Scenario Kosovo would be eligible as the beneficiary country of a CDM. An Annex I Country might propose to develop a CDM Project in Kosovo, in order to get CERs, used to reach his internal target or to sell them on the Carbon Market. On the other hand in this Scenario it won’t be possible to implement flexibility mechanisms like Emission Trading or Joint Implementation, both requiring the country (also the beneficiary for JIs) to belong to Annex I. By the way, the actual possibility to develop a CDM Project strongly depends on its characteristics and, above all, its capacity to obtain a reduction of the CO2 emission in comparison with a defined baseline.



The definition of a realistic baseline is probably the most crucial issue of this chapter, cause it requires to make several assumptions regarding the country development in the next years. Moreover, in order to accept a CDM Project, the baseline must be defined not only doing reasonable hypothesis, bus also taking into account economical and technical factors. As defined by the UNFCCC, the baseline scenario must be identified, between the alternatives, as the most economically attractive. In this chapter, whose aim isn’t to present a detailed methodology but just to give an idea of what could be the impact of the Project within this Scenario, a simplified and reasonable baseline will be defined. For both cases (baseline and Project implementation) the following assumptions have been made: • Till 2014, the growth in demand is covered rehabilitating both Kosovo A and Kosovo

B power plants, as detailed in Par. 1.1.1.3 of Task 1. For these plants these average values of efficiency have been assumed: 21% for all Kosovo A units (2 tCO2/MWh) and 32% for all Kosovo B units (1,4 tCO2/MWh). In both scenarios Kosovo B is supposed to retire in 2030. Other common assumptions are that imports are not considered in the energy balance, and that all the energy that is generated over the demand is exported.

From 2014 the development is different between the Baseline and the Project implementation: • In the baseline, the demand is supposed to be covered at first by the extension of

generation of Kosovo A, for which the same characteristic (load factor, capacity…) of the previous years can be reasonably assumed. After Kosovo A retirement in 2020, the installation of new capacity will be necessary to cover the demand forecasted. In this scenario, a new conventional Lignite Fossil Plant is supposed to be installed. The new capacity, that will be installed progressively from 2020 just in order to cover the increasing demand, will reach 1500 MW in 2030 (as shown in Figure 4). For this plant, based on a conventional steam cycle, a reasonable 37-38 % of efficiency is assumed (1,20 tCO2/MWh). As Figure 6 shows, the commissioning of the new power plant causes at first a decrease of the CO2 emissions (due to its replacement of Kosovo A, characterised by higher specific emissions). Then, as the capacity installed increase, the emission level raises until about 13 Mt CO2 /year. In this scenario the export is reduced to minimum level, as shown in Fig.5.

• In the Project scenario, the further demand is covered only by a new 2000 MW

Super Critical Power plant. Kosovo A and Kosovo B go out of work, as foreseen, respectively in 2013 and in 2030. Figure 6 shows that, while during the first years Kosovo A retirement takes to a CO2 emissions decrease, from 2018 emissions start increasing reaching almost 22Mt in 2020, when all the new capacity is in operation. Then, after Kosovo B retirement in 2030, total CO2 yearly emissions decrease to about 16 Mt. If compared with the baseline, the Project Scenario is then characterised by higher CO2 emissions. While the efficiency of the new power plant is higher (for Super Critical steam cycle an emission rate of 0.85 t/MWh is assumed) in this Scenario a lot of energy is generated in surplus, and so it must be exported, as shown in Fig.5. If the baseline mentioned above had been correctly defined, this Project



could not be proposed to the UNFCCC as a CDM proposal, cause it does not take to an emission reduction, as shown in Fig.6. Besides, if the baseline was differently defined, the results may dramatically change. For instance, if the installation of a capacity equal to the one of the Project Scenario, but based on a Conventional Steam Cycle, was proposed as a baseline, then the Super Critical Project would takes to an emission reduction, as shown in Fig.7. In this case, if the baseline was accepted by UNFCCC and a CDM project was developed, the ANNEX I Country that decided to invest in such Project would receive an amount of CERs calculated on the basis of the reduction obtained. Considering an average reduction of about 4 Mt for each of the 7 years of the crediting period, and assuming a price of the CO2 of 20€/t, the investor would earn about 80M€/year.

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Fig.7 – CO2 emissions

2.4 Scenario 3 The basic assumption of this scenario is that Kosovo ratify the Kyoto Protocol in the near future and that an emission cap is fixed for the Country. In this hypothesis, Kosovo would become an Annex I country. It is very difficult now to foreseen the limits that will be fixed for Kosovo, for the fact that they will be chosen on the basis of a framework that is not yet defined at the moment. For instance, if the cap level was fixed considering the power plant situation before the installation of the new PP, from one hand it would be adjusted on a high specific emission level (tCO2/MWh), but from the other hand it would take as a reference the export level of these years, so the level fixed could be too low to be sustainable in the following years, in which an higher amount of energy exported is foreseen.. Figures 8 and 9 show, in a simplified way, the different scenarios that could be developed in the case, respectively, that: • the power generation cap level is fixed with the aim of generating a reduction of the

emission (i.e. 8%) in comparison with the emission of 2013, year in which the 2000 MW power plants has not been built yet (Figure 8). In this case, since 2014, the new power plant emissions would be always higher than the ones allowed, so the power generation sector of the country would have to pay the relative amount, or it would apply some emission trading mechanisms between other industrial sectors or foreign countries.



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• the power generation cap level is fixed with the intention of generating a reduction of the emission (i.e. 8%) in comparison with the emission of 2020, year in which the 2000 MW power is already in operation (Fig.9). In this case, since 2020, the new power plant emissions would be higher for the first years but, after Kosovo B retirement, they would be lower than the ones allowed, and the generation sector would earn the relative amount of money.



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Moreover, from an external point of view, if Kosovo ratified Kyoto and became an ANNEX I Country, it would lose the possibility to be beneficiary of CDM Project, being ANNNEX I, but it could implement JIs Project, both as Proposal and as Guest. As described in the previous chapter, a JI Project may be simpler to develop in comparison with a CDMs one, especially if it follows the Track 1 Procedure, which can be applied if the Countries satisfy the eligibility criteria.

2.5 Scenarios evaluation Stating in advance that the scenarios described here above could be all realistic, it must be said that the development of the Country in relation of this topic is difficult to forecast, cause it depends more on political choice than on technical ones. With the aim to imagine the most probable evolution, first of all it is reasonable to foreseen that Kosovo will ratify the Protocol, for the convenience of being allowed to be the beneficiary of CDMs Projects, which could be economically attractive for Annex I countries. Actually, it must be said that if the size of the new Power Plant was the one supposed, then it would be very hard to sustain a CDM proposal in which the baseline of comparison would be characterised by a lower capacity. On the other hand it would be difficult, as said before, that Kosovo might accept an emission cap, especially in the near future. Actually, for many experts this assumption is far from being realistic. Taking a look at the list of the Countries who have ratified the Protocol in the last years it is easy to find developing countries, but few of them have



received an emission limitation. That could be explained by the fact that most of the developing countries find unfair to have an emission cap in this years of developing, while Annex I countries haven’t had any limitation for almost all the last century. Actually, it is improbable to imagine Kosovo or other developing countries accepting an emission cap while some countries that represent the main sources of CO2 emission have not even ratified the protocol (i.e. U.S.A, Australia, China, Brazil..). For these reasons, between the three scenarios here above presented, the second one may be the most probable.



3 CONCLUSIONS

The main aim of the Task was to review the Carbon Market and his related mechanisms. While the first chapter has illustrated the characteristics of the main flexibility mechanisms that exist at the moment in order to lower the CO2 emission amount, the finality of the second chapter was to analyse in which way such mechanisms may find implementation in the Kosovo context. The first conclusion that is possible to draw is that the development about this topic strongly depends on whether Kosovo will ratify the Kyoto protocol or not. In some way it is possible to say that this decision would move Kosovo from a passive position to an active one. If Kosovo will ratify Kyoto in fact, besides not having any emission cap to respect, it would take the position of “beneficiary” country of a Clean Development Mechanism Project, held by an Annex I Country. Starting from the current situation of Kosovo, it could be economically interesting for a UE Country, for instance, to invest in a CO2 reduction project, cause the implementation of modern technologies could bring more significant results if it takes place in a low efficiency background, like the one of Kosovo. Besides, the results are strongly related with the situation that is defined as a baseline. As a general conclusion it is possible to say that if the Project is compared with a baseline in which a similar capacity is installed, then the USC technology may be a strong alternative from the CO2 emissions point of view. Otherwise, if the baseline was defined developing a situation similar to the actual one, in which the total capacity is designed just to cover the demand, then the project, even if characterised by high efficiency, would be penalised for what concern the flexibility mechanisms implementation. Moreover, if Kosovo decided to ratify Kyoto, probably an emission cap would be fixed for the Country. In this case the height of this cap would contribute in the determination whether an investment, such the one of the 2000 MW power plant, is economically interesting or if it isn’t. In the second chapter a simplified example has been proposed, in order to feel the different development that would occur with variations of the level of emissions allowed. With the Kyoto ratification and the cap level assignment, becoming Annex I, Kosovo would not have the possibility to benefice anymore of CDM Projects but, on the other hand, he would have the chance to take part in Joint Venture Projects, both as proposal and as guest. These kinds of Project, if compared with CDMs, can be easier to be developed, especially if both the Countries satisfy the eligible criteria.

November, 2007





Task 3.2.C

PLANT BASELINE DESIGN REPORT

Studies to support the development of new generation capacities and related transmission Page 2 (43) Task 3.2.C, Baseline design November, 2007


Disclaimer

While the consortium of Pöyry, CESI, TERNA and DECON considers that the information and opinions given in this work are sound, all parties must rely upon their own skill and judgment when making use of it. The consortium members do not make any representation or warranty, expressed or implied, as to the accuracy or completeness of the information contained in this report and assumes no responsibility for the accuracy or completeness of such information. The consortium members will not assume any liability to anyone for any loss or damage arising out of the provision of this report.

The report contains projections that are based on assumptions that are subject to uncertainties and contingencies. Because of the subjective judgments and inherent uncertainties of projections, and because events frequently do not occur as expected, there can be no assurance that the projections contained herein will be realized and actual results may be different from projected results. Hence the results and projections supplied are not to be regarded as firm predictions of the future, but rather as illustrations of what might happen. Parties are advised to base their actions on an awareness of the range of such projections, and to note that the range necessarily broadens in the latter years of the projections.



CONTENTS

1 INTRODUCTION..............................................................................................................5

1.1 Plant Net Capacity................................................................................................................8 1.2 Steam Parameters .................................................................................................................9

2 STEAM BOILER .............................................................................................................12

2.1 Design fuel and emissions..................................................................................................12 2.2 Design Capacity .................................................................................................................15 2.3 Pulverized fired boilers 500 and 750 MW .........................................................................16 2.4 Circulating Fluidized Bed boiler for 500 MW ...................................................................17 2.5 Flue Gas Cleaning ..............................................................................................................17 2.6 Boiler Feed Water Pumps ..................................................................................................20

3 STEAM TURBINE PLANT............................................................................................22

3.1 Steam Turbine Concepts ....................................................................................................22 3.2 Start-up and by-pass systems .............................................................................................22 3.3 Cooling Water System .......................................................................................................23

4 BALANCE OF PLANT ...................................................................................................25

4.1 Lignite Supply ....................................................................................................................25 4.2 Ash Systems .......................................................................................................................26 4.3 Water Treatment.................................................................................................................28 4.4 Oil / Start-up Systems ........................................................................................................35

5 ELECTRICAL SYSTEMS..............................................................................................37

6 AUTOMATION ...............................................................................................................39

7 CIVIL STRUCTURES ....................................................................................................41

8 PERFORMANCE OF THE PLANT..............................................................................43

List of Tables Table 2-1 The results of the lignite sample analysis. .........................................................................13 Table 2-2 The results of the ash analysis. ..........................................................................................14 Table 4-1 Investment costs for 4 500 MW unit. ................................................................................34 Table 4-2 Operation and maintenance costs. .....................................................................................34 Table 8-1 The auxiliary power demand. ............................................................................................43



List of Figures Figure 1. Construction schedule of units..............................................................................................8 Figure 1-2 500 MW PF–boiler plant. .................................................................................................10 Figure 1-3 500 MW CFB-boiler plant................................................................................................10 Figure 1-4 750 MW PF-boiler plant...................................................................................................11 Figure 2-1 Illustration of the wet lignite special heating surfaces. ....................................................18 Figure 2-2 Wet flue gas desulphurization system. .............................................................................19 Figure 2-3 Flue gas desulphurization – Limestone grinding..............................................................20 Figure 2-4 Boiler feed water pumps...................................................................................................21 Figure 3-1 The by-pass system of the steam/water cycle...................................................................23 Figure 4-1 Schematic arrangement of lignite yard operation.............................................................25 Figure 4-2 Pile arragengement for a 500 MW unit with one stacker-reclaimer. ...............................26 Figure 4-3 Ash disposal systemp of the PF-boilers............................................................................27 Figure 4-4 Ash disposal system of CFB fired boiler..........................................................................27 Figure 4-5 Map of the water systems. ................................................................................................29 Figure 4-6 The principle of the water treatment system. ...................................................................29 Figure 4-7 The principle of a typical water treatment plant...............................................................30 Figure 4-8 The principle of a demineralising plant............................................................................31 Figure 4-9 Water balance 500 MW PF unit. ......................................................................................31 Figure 4-10 Water balances 500 MW CFB-plant above and 750 MW PF below. ............................32 Figure 4-11 Cost of water...................................................................................................................33 Figure 4-12 Capacity of the 500MW plant on fuction of ambient temperature.................................33 Figure 4-13 The cost of the saved water. ...........................................................................................35 Figure 4-14 The oil/back-up start system...........................................................................................36 Figure 5-1 Single line diagram of the 500 / 750 MW units (for clarity reasons only two units shown

with the black start generator and 110 kV back-up connection)................................................37 Figure 6-1 The hierarchical structure of the distributed control system. ...........................................39 Figure 6-2 The control room displays and keyboards (per one unit). ................................................40



1 INTRODUCTION This report presents proposed preliminary designs for the new mine mouth thermal power plant of 2000 MW total capacity for further analysis and development. The justification to select these three configurations in May was as follows:

TOR for Task 3 outlines among others: Based on the findings of above, power market review, transmission system assessment and power plant and unit maximum size assessment, the Consultant will revisit the options assessed in the pre-feasibility study for the new power plant, should identify and rank the three preferred options for plant size and unit size configurations and the technologies at the selected sites to be evaluated further as described in the economic and financial analysis.

Based on the findings of power market review, transmission system assessment and power plant and unit maximum size assessment, the Consultant will revisit the options assessed in the pre-feasibility study for the new power plant, should identify and rank the three preferred options for plant size and unit size configurations and the technologies at the selected sites to be evaluated further as described in the economic and financial analysis.

Electricity market viewpoint The electricity market review report (Task 1) confirms that there is sufficient demand for power and the price level even with normal growth scenario will make the plant construction attractive. It is estimated that the 2000 MW new plant could sell 14,9 TWh/a of electricity. The first unit could start 2012-13 and the plant will be completely built by 2018.

Transmission system viewpoint The transmission study (Task 2) in its stability analysis part concludes that the existing 400 kV network around Kosovo cannot support larger units than 500 MWnet. A larger unit would loose its synchronism in case of a transmission line loss.

Technology viewpoint Today´s unit sizes for coal/lignite/brown coal fired plants are typically in a range of 5-700 MW. Even larger units up 1100 MW are in construction where the transmission networks and fuel supplies would allow that size. However, a large unit size also requires larger reserve/spare capacities and only big utilities or well functioning electricity electricity market makes that possible. Main part of the new plants is in 6-700 MW range like China. Carbon credits easily doubles or triples the initially available cheap fuel cost. The fact pushes the plant owners and developers to search for higher efficiencies. It also justifies large units as there it is easier and more economical to apply more sophisticated processes. The current target figures are in a range of 43 % for lignite fired plants with supercritical steam parameters. A subcritical plant in lignite firing hardly reaches 39-40 %.



Sibovc lignite contains considerable amount of Calcium in the form of limestone aside sulphur. That fact makes application of Circulating Fluidized Bed (CFB) combustion attractive as the combustion process will directly take care of the desulphurization of the flue gases. Whereas Pulverized Fired (PF) boiler would need post desulphurization process after the actual steam boiler. Typically a separate desulphurization plant adds some 10 percent to the cost of the boiler plant and it is also reducing the plant efficiency as its auxiliary power is considerable. Today´s all large lignite fired boilers >400 MW apply PF-technology. The largest CFB-boiler plant in operation is 350 MW and there is one 460 MW unit under construction. Investors point of view All the indications are there that the proposed 2000 MW new power plant is viable. Provided that the investor has sufficient risk taking and funding capability it would be quite advantageous to build the complete plant without dismantling the construction organization i.e. units should follow each other with 12-18 month intervals. Tentative cost figures The following table indicates tentative investment an operating cost figures and performance of different types and unit sizes to make 2000 MW. It has to be considered preliminary.

Guideline cost figures:Unit type PF CFBUnit size 500 MW 660 MW 500 MW 400 MW 300 MWEfficiency 42 % 42,5 % 42,3 % 39,0 % 38,8 %

Unit investment M€ 820 1000 800 675 520Total plant cost M€ 3280 3000 3200 3375 3640*Relative cost % 109,3 100,0 106,7 112,5 115,5

Fuel cost M€/a** 128,6 127,1 127,7 138,5 139,2 O&M cost M€/a 41,3 37,5 37,5 42,0 43,5Total M€/a 169,9 164,6 165,2 180,5 182,7Difference M€/a +5,3 lowest +0,6 +15,9 +18,1

* 2100 MW total capacity, 7 units** 1€/GJ fuel cost, 8,2 €/ton

Only 500 MW CFB (supercritical) can compete with PF-units



Proposed alternatives to be studied to make 2000 MW 1. The most probable concept is 4 x 500 MWnet (around 535 MW gross) pulverized

fired plant with supercritical steam parameters (260-275 bar/580-600 °C with reheat). Its efficiency is 42-43 % and it will be equipped with wet flue gas desulphurization plant. The plant will be built in 5-6 years.

2. As a challenger a similar plant with the same steam parameters but applying CFB-

combustion. The efficiency will be the same as above or slightly better. No FGD required.

3. The first unit will be 500 MW PF-plant as Alt.1 and thereafter two 750 MW units , will be built to make totally 2000 MW.



Proposed schedule

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

500 MW units

750 MW units

0200400600800

100012001400160018002000

Cap

acity

MW

Year

New TPP Construction Schedule

500 MW units 750 MW units

Figure 1. Construction schedule of units

The first unit will be operational by 2014 and the plant is fully built in 5 years.

It has been selected the following concepts:

4 x 500 MW net applying pulverized firing 4 x 500 MW net applying CFB-combustion technology 1 x 500 MW plus 2 x 750 MW net applying pulverized firing

It has also been assumed that the plant will reach its final capacity without any major interruptions in the construction schedule i.e. in 5-6 years from the first unit reaching commercial operation.

1.1 Plant Net Capacity The plant is assumed to have conventional evaporative cooling towers to dissipate the heat from the turbine condensers. The average ambient temperature of Pristine is slightly above 10 °C and the average relative humidity is close to 80 %. The plant is currently assumed to have an exhaust pressure of 0,04 bar equalling to 15 °C cooling water temperature from the evaporative cooling tower.



The electricity market analysis does not give any clear premium for the capacity during hot weather peaks i.e. the plant can be designed as base load energy producer. Later a cold end optimization (turbine LP-part – condenser – cooling tower) may justify that lower condenser pressure especially if high CO2-credits are included. The current concept is a low initial cost approach with fairly good performance – a standard configuration in many power plants all around the world.

1.2 Steam Parameters The new power plant units have single reheat system and the following supercritical steam parameters at the turbine inlets:

500 MW

PF 270 bar/600 °C , 47 bar/600 °C

CFB 270 bar/600 °C, 47 bar/600 °C

750 MW PF 270 bar/600 °C, 47 bar/600 °C

The selection of the se steam parameters is based on the recently built or currently constructed large plants in Europe. The fuel to be utilized does not contain any harmful elements in quantities that would restrict the new plant in Kosovo to apply those parameters.



PF

1182 MWfG

531 MW

G

531 MW

185 °C, 11.2 bar(a)185 °C, 11.2 bar(a)

270 bar, 600 °C, 352 kg/s

46 bar, 600 °C, 308 kg/s

12,2 kg/s

238 kg/s0,04 bar

12 bar, 278 kg/s

280 °C

LP-eco

HP-eco

218 °C

264 °C

Kosovo C, 500 MW PF unitsSimplified steam-water diagram

Net efficiency 42,3 %

13 000 kg/s

15 °C

Figure 1-2 500 MW PF–boiler plant.

PF

1186 MWfG

533 MW

G

533 MW

185 °C, 11.2 bar(a)185 °C, 11.2 bar(a)

270 bar, 600 °C, 354 kg/s

46 bar, 600 °C, 309 kg/s

12,2 kg/s

239 kg/s0,04 bar

12 bar, 279 kg/s

280 °C

LP-eco

HP-eco

218 °C

264 °C

Kosovo C, 500 MW CFB unitsSimplified steam-water diagram

Net efficiency 42,2

13 000 kg/s

15 °C

Figure 1-3 500 MW CFB-boiler plant.



PF

1782MWf G

793 MW

G

793 MW

185 °C, 11.2 bar(a)185 °C, 11.2 bar(a)

270 bar, 600 °C, 521 kg/s

46 bar, 600 °C, 458 kg/s

18,2 kg/s

356 kg/s0,04 bar

12 bar, 415 kg/s

280 °C

LP-eco

HP-eco

280 °C

280 °C

Kosovo C, 750 MW PF unitsSimplified steam-water diagram

Net efficiency 42,5 %

19 500 kg/s

15 °C

Figure 1-4 750 MW PF-boiler plant



2 STEAM BOILER

2.1 Design fuel and emissions The Sibovc lignite resource found in Kosovo can be characterized with the following analysis as received (>8000 samples analyzed in the 1970-80´s):

Heat value, LHV kJ/kg 8200 - range kj/kg 6000-9500 Ash % 15,3 - range % 10-30 Moisture % 42 - range % 40-50 Sulphur, total % 1,1 - range % 0,7-1,5 Sulphur, combustible % 0,35 - range % 0,1-0,7 Additionally during this study work 8 drills were made to test the lignite mainly for harmful elements in the fuel as they have not been analyzed before. The results of these tests can be summarized in the following



Table 2-1 The results of the lignite sample analysis.

Item Average Maximum Minimum Moisture % 42,46 47,1 33,8 Ash % 33,06 44,7 20,2 Ash (as received) % 19,23 28,7 10,9 Volatile matter % 44,53 51,1 36,8 Volatile matter (as received) % 25,52 28 21,2

C-fix % 22,42 28,7 15,3 C-fix (as received) % 12,79 16,1 9,3 Sulphur S % 1,98 3,07 1,1 Sulphur S (as received) % 1,15 1,98 0,65 Sulphur S (inorganic) 3,64 5,21 1,58 Chlorine Cl % <0.01 <0.01 <0.01 Chlorine Cl (as received) % <0.01 <0.01 <0.01 Carbon C % 42,30 50,7 34,9 Carbon C (as received) % 24,22 27,3 20,2 Hydrogen H % 3,11 3,8 2,7 Hydrogen H (as received) % 6,54 7,2 5,7 Nitrogen N % 0,86 1,3 0,66 Nitrogen N (as received) % 0,49 0,75 0,4 Oxygen O % 18,68 22,7 14,3 Oxygen O (as received) % 48,37 53,4 39,8 Fluorine F (dry basis) mg/kg 63,25 125 33 Calorific Value MJ/kg 16,19 19,544 13,489 Calorific Value (as received) MJ/kg 9,27 10,555 7,989

Emission factor (calc.) t/TJ CO2 99,86 103 96,9 Ash Deformation temperature °C 1223 1280 1180 Hemisphere temperature °C 1260 1360 1200 Flow temperature °C 1273 1360 1200



The resulting ash has also been analyzed with the following summary results:

Table 2-2 The results of the ash analysis.

This Kosovo lignite can be characterized by its relatively low ash content, low combustible sulphur as the most of the sulphur is found in inorganic sulphate/sulfite form and the existence of ample calcium in the fuel. The ash softening and melting

All figures in mg/kg Item Average Maximum Minimum Silicon Si 145 000 210 000 81 000 Siliconoxide SiO2 310 000 450 000 170 000 Calcium Ca 123 500 320 000 45 000 Calciumoxide CaO 170 000 450 000 63 000 Aluminium Al 77 500 130 000 11 000 Aluminiumoxide Al2O3 145 000 250 000 21 000 Iron Fe 50 500 78 000 30 000 Ironoxide Fe2O3 72 000 110 000 43 000 Potassium K 7 000 14 000 2 400 Potassiumoxide K2O 8 500 17 000 2 900 Magnesium Mg 20 500 30 000 9 300 Magnesiumoxide MgO 34 500 50 000 16 000 Manganese Mn 490 3 000 270 Manganeseoxide MnO2 765 4 700 430 Sodium Na 4 050 6 600 1 200 Sodiumoxide Na2O 5 450 8 900 1 600 Phosphorus P 535 1 300 400 Phosphorusoxide P2O5 1 200 3 000 920 Titanium Ti 2 350 4 400 1 100 Titaniumoxide TiO2 3 900 7 300 1 800 Antimony Sb 3 5 3 Arsenic As 48 81 20 Lead Pb 28 53 8 Barium Ba 535 1 000 270 Beryllium Be 3 3 3 Boron B 305 570 69 Cadmium Cd <0.50 0 0 Cobalt Co 16 24 8 Copper Cu 52 92 17 Mercury Hg <0.045 0 0 Chromium Cr 150 230 63 Molybden Mo 14 34 11 Nickel Ni 200 480 90 Vanadium V 130 180 42 Tin Sn 3 4 3 Zinc Zn 84 110 29



temperatures are low and may cause problems in conventional pulverized combustion process if not properly considered at the design phase. The presence of calciumcarbonate, CaCO3, in the fuel has been analyzed during this study work. The percentage of calciumoxide, CaO, in the ash varies between 6 and 45. The average is 17 %. The minimum percentage gives Ca/S molar ratio of 4-5 which is at the limit of “self desulphurization” in a CFB combustion. However, the average percentage give a safe ratio of >10. Emission Requirements It is assumed that the new thermal power plant, TPP, will fully comply with the EU Large Combustion Plant, LCP, rules. That will mean the following emission levels from the beginning of the operation:

Sulphur dioxide, SO2 mg/nm3 200 Nitrogen oxides, NOx mg/nm3 200 Particulates mg/nm3 30 A provision is made what regards to space requirements for a CO2-capture facility in the future. The capture process is assumed to be based on flue gas washing with amines and then the washing liquid is regenerated with steam taken from the turbine plant. The space for the flue gas washer is like a wet flue gas desulphurizer (FGD) but the space for the regeneration/compressing facility would need approximately 220 x 60 meters aside the plant.

2.2 Design Capacity The steam boilers are designed to be able to reach their full capacity also on the following low quality lignite (within range) as there will not be any homogenization of the lignite extracted from the mine before its introduction into the combustion process:

Design Range Heat value, LHV MJ/kg 8,2 6,0-10,0

Moisture % 45 40-50 Ash % 15,3 10-25 Sulphur, combustible % 0,7 0,3-1,0

The boiler capacities in different unit sizes and combustion methods are tentatively as follows: Alternative Capacity MWth Steam HP kg/s RH kg/s 500 MW, PF 1182 352 308 500 MW, CFB 1186 354 309 750 MW, PF 1782 521 458 The typical lignite consumption and ash are with the design fuel as follows:



Alternative Lignite Ash t/h t/MWh t/h 500 MW, PF 519 1,04 80 500 MW, CFB 521 1,04 80 750 MW, PF 782 1,04 120

2.3 Pulverized fired boilers 500 and 750 MW The lignite fuel is delivered to the boiler silos pre-crushed i.e. the maximum size of the fuel is <40 mm. For pulverizing of wet lignite beater wheel pulverizers are most commonly used. There hot flue gases from the upper furnace are sucked for drying the wet fuel. The fuel is fed into the hot inlet duct and the drying fuel flue gas mixture passes trough the radial fan type pulverizer where the actual pulverizing takes place by gravitational force as the fuel clumps collide against the fan enclosure wall made of abrasion resistant wear parts. The upper part of the pulverizer has a classifier that allows only fine particles to pass and coarse fraction is recycled back to the pulverizing process. The maximum capacity of a single pulverizer is approximately 150-200 t/h i.e. 500 MW unit needs four-six pulverizers depending on the fuel range (8200, minimum 6000 kJ/kg). The large 750 MW unit will need 5-7 pulverizers. In order to have continuous operating capability there has to be one spare pulverizer as they need periodic maintenance at 2-4000 hrs intervals with Kosovar lignite.

For large boilers tangential firing method is commonly applied and each pulverizer is feeding its own four burners i.e. one level. The burners fed by different pulverizers are in stacked form close to the corners to produce a swirl in the centre of the furnace. The burners are Low NOx-type where the combustion air is staged to reduce the absolute maximum temperatures in combustion thus effectively reducing the formation of thermal NOx. Another burner arrangement is to locate them on all the walls and direct the flame towards the swirl in the centre of the furnace.

The fluegas air pre-heater is normally of rotary type and due to the size of flue gas stream there may be two parallel units each designed for 50 % flow.

The steam boiler itself is either built in tower form or as two-pass unit. The furnace and the boiler walls in the hot sections are of membrane construction welded gastight. Tower format saves space as the super-, reheater and economizer heating surfaces are stacked above the furnace. The upper part of the boiler may be split into two sections by a wall that also acting as a heating surface. The flue gas after the economizer are leaving high up and there has to be a duct to bring those flue gases down to the air preheater.

A two-pass configuration will need slightly more space in longitudinal direction than the tower boiler but the benefit is that the connecting pipelines are slightly shorter. Today the tower boiler is more popular.



At the moment it is assumed that the pulverized fired boilers can meet the nitrogen oxide emission limits with proper burner arrangement without any additional treatment of the flue gases after the furnace.

Regarding to sulphur dioxide emissions it is expected that wet desulphurization process is installed after the PF-boilers. If the proposed continuous measuring programme at Kosovo B or any other testing will verify the high degree of sulphur capture in the furnace also dry or semi dry desulphurization approaches can be considered.

2.4 Circulating Fluidized Bed boiler for 500 MW The CFB-boiler would be a state of art supercritical steam boiler with reheat as currently there are no such boilers in operation. One, 460 MW unit in Poland, is under construction. It is expected to be operational by early 2009.

The applied combustion temperature of 850-950 °C is quite ideal for calcination of limestone in the fuel to calcium oxide. That CaO captures sulphur of the the fuel during the combustion process. The desulphurization process is not as effective as in the separate flue gas desulphurization process. Compared with S-moles, typically 3 times more Ca-moles are required to reach 90 percent desulphurization degree vs. that of 1,0 for a downstream FGD. However, in this particular case as the lignite contains a substantial amount of limestone, CaSO4 and the sulphur content of the fuel is low (Ca/S mole ratio >5-10) it can be expected that the sulphur dioxide emission will be extremely low..

The low combustion temperature of CFB results also in low thermal NOx-formation as the emission almost exclusively comes from the nitrogen in the fuel.

Typically the lignite injected into furnace shall have an average particle size of 1 mm and the maximum of 10 mm. There should not be more than 5 % fine particles of 0,05 mm or less. Final crushing of the fuel is executed outside of the boiler house at the fuel yard or alternatively the the crushers are located at the discharge points from the boiler silos.

To start the operation the boiler needs sand to create the necessary inventory of the circulating hot mass for ignition. During its normal operation the fuel ash may be sufficient to maintain that inventory level. If the fuel ash is not able to upkeep the inventory level some (quarz) sand has to be added every now and then.

The fuel ash exits the boiler mostly (about 90 %) in the form of fly ash and the rest is taken out in dry form as bottom ash through ash cooling screws.

2.5 Flue Gas Cleaning All the boilers have one or two parallel flue gas lines and there are electrostatic precipitators after the air preheater(s). Those ESP´s have 4-5 electrical fields and the final dust content is reached with even one field out of operation.



Air Preheater – Flue Gas Cooling

In order to effectively utilize the heat of the high flue gas flow coming from wet lignite special heating surfaces are arranged as the following sketch illustrates:

HPBFW

LP condensate

ESP160 oC 80 oC

55oC

130oC

Rotary AH

SAH

380 oC300 oC

ID Fan

Air to combustion from FD fans

Flue gas from economizer

20 oC

Figure 2-1 Illustration of the wet lignite special heating surfaces.

The rotary air preheater does not need all the flue gas flow from the furnace and a parallel duct with heating surfaces can be built. The flue gas can be cooled from approximately 380 °C down to 160 °C as the air preheater. It is proposed to use LP-condensate after the main condensate pumps up to 150 °C (as the condensate is entering the deaerator) and HP-boiler feed water parallel to the HP-heaters. The flows are adjusted to utilize the available heat in the flue gas i.e. there are controls on the condensate and feedwater flows as well as on the flue gas flow. The primary target is anyhow that the air preheater receives sufficient flow to maintain the outlet temperature of the combustion air constant at approximately 300 °C.

Another boiler efficiency improvement is to cool the flue gases after the electrostatic precipitator by installing a heating surface to heat a closed loop circulation water to preheat the combustion air prior to its introduction to the air preheater (replacing traditional steam air preheater “SAH”). The materials have to be plastic coated in order to reduce the risk of acid corrosion as the temperatures are there below the acid dew point of the flue gas.



Flue gas desulphurization

In case of pulverized firing it is assumed that the flue gases will contain more SO2 than allowed to release into the atmosphere. The limit by the EU LCP directive is 200 mg/nm3 at 6 % O2. A desulphurization plant is required and that is normally installed after the electrostatic precipitator and in this case also after the heat recovery system for combustion air preheating described above. A wet flue gas desulphurization system is assumed. That will use ground limestone as a reagent and the end product is industrial grade gypsum and waste water.

The system is as the following diagram illustrates:

Pulverized limestone

Flue gas

Air

Clean gas

Water

Gypsum

Effluent

Typical wet flue gas desulphurization system

Limestone preparation Flue gas cleaning Gypsum dewatering

Figure 2-2 Wet flue gas desulphurization system.

Limestone can either be purchased as ground pulverized material or many plants buy limestone lumps and prepare the pulverized limestone for slurry preparation in ball mill facility. A typical system system is illustrated below. Both approaches are possible in Kosovo as there is a local limestone quarrying operation close to Macedonian border. The company operating the quarry is able to deliver either limestone in lumps or pulverized (even in quick lime format).



FGD Limestone Grinding

MMM

MM

W

WFeed Bin

Vibrating BinDischarger

Weight Feeder

W

Grinding WaterSupply

Ball Mill

Ball Charge

Distribution system

OpteratingSlurry Pump

Mill SlurrySump w/Agitator

Product Slurry Tankw/Agitator

Figure 2-3 Flue gas desulphurization – Limestone grinding.

2.6 Boiler Feed Water Pumps The boilers for 500 or 750 MW units have three boiler feed water pumps. Two of those are designed for with electric motor drives with hydraulic couplings for speed control. In order to be able to start those large motors their capacity is limited to 6-7 MW i.e. 500 MW units have 2 x 35 % pumps and 750 MW units only 2 x 25 %. These pumps are mostly used for start-ups and in emergency cases when the main turbine driven pump is down.



2 x 25%electric

185 °C, 10 bar(g)185 °C, 10 bar(g)185 °C, 10 bar(g)

100%

750 MW units

2 x 35%electric

185 °C, 10 bar(g)185 °C, 10 bar(g)185 °C, 10 bar(g)

100%

500 MW units

15,6 MW 23,4 MW

320 bar 320 bar

Figure 2-4 Boiler feed water pumps.

The steam turbine drive may have its own condenser or in some cases it may be located close to the main condenser and that is used. A separate condenser will offer more flexibility in operation.



3 STEAM TURBINE PLANT

3.1 Steam Turbine Concepts 500 MW units The main steam parameters have been proposed to 270 / 46 bara 600/600 oC. These supercritical steam parameters mean separate High pressure and Intermediate pressure casings as basic solution.

Number of the low pressure casings depends on unit size and turbine process cold side optimisation. In 500 MW unit only one LP casing solution is quite possible though optimal configuration may also be two LP casing concept. The key issue is the electricity valuation price and steam turbine vendor standard LP casing exhausts areas. Most vendors though have large enough LP last stage blades (titanium) to handle the 500 MW units with only one two flow LP casing but this may request increased exhaust pressure and large losses in the cold end.

The optimal number of feed heating stages is 8 +1 where the 8th heater is in the high pressure side. It means that there is a fairly expensive/complicated bleeding point in the HP-turbine casing.

750 MW units

The main steam parameters are the same as for 500 MW i.e. 270 / 46 bara 600/600 oC.. There are two low pressure casings.

Turbine modelling The TURSIM model sheets can be found in Annex 1. The sheets illustrate the turbine process including the deviations of the LP-condensate and HP-feedwater to the fluegas heating surfaces parallel to the rotary air preheater.

3.2 Start-up and by-pass systems Supercritical steam cycles are fairly fast to start even from cold conditions as the water volumes inside the boiler are low. Typical figures are:

Type of start Time from first fire hours Cold start (>36 hrs) 2,5 – 4 Warm start (<24 hrs) 1,5 – 2,5 Hot start (<8 hrs) 0,5 – 1,5

The steam and water cycle has by-pass systems for start-ups and turbines trips: The HP by-pass system diverts the superheated steam with cooling to the cold rehaeter inlet line as the sketch below illustrates.



Boiler

GG

185 °C, 11.2 bar(a)185 °C, 11.2 bar(a)

270 bar, 600 °C46 bar, 600 °C by-pass system 50 –(100) %

12 bar

LP-eco

HP-eco

280 °C

100 %

Figure 3-1 The by-pass system of the steam/water cycle.

There are no safety valves on the high pressure side as the by-pass system relieves steam in case of turbine trip into the cold reheat line. The reheat lines have safety valves on both sides of the boiler but the hot side has priority to open if the by-pass system into the condenser is not fast enough or its capacity is limited.

The boiler has a water separation bottle(s) with water recycling back to the economizer in some designs. Others may dump the water separated into the blowdown vessel during star-up.

3.3 Cooling Water System

3.3.1 Condensing Method The main condenser will be of shell and tube type surface condenser. They will be of two pass configuration with vertically split water chambers in order to facilitate partial operation in case of tube failure.

3.3.2 Material Selection The main condenser surfaces are in contact with ambient air (shell), main cooling water (tubes and water chambers) and circulating steam/water (tubes, shell and hotwell).



The estimate for the circulating cooling water analysis is based on that there will not be lack of makeup water and thereby the circulation rate will be relatively low keeping the water chemistry in reasonable concentrations. Based on the CW chemistry the main condenser will have stainless steel tubing (preferably high grade SS). Titanium tubing being even better but not necessary if the CW chlorine concentration is maintained within prescribed limits by blow down and make-up water.

3.3.3 Circulation system The cooling water is circulated from the evaporative cooling tower basin to the turbine condenser and back by two 50 % circulation pumps. Additionally there will be two small pumps for start-up phases. The estimated circulation volumes are as follows for different unit sizes and combustion methods:

Concept Flow kg/s 500 MW PF 13 000 300 MW CFB 13 000 750 MW PF 19 500

The pumping head is typically around 20 m and that will be defined at the actual design phase of the plant. The pumps need 3,5 – 5,0 MW electrical power.

The circulation system has a continuous rubber ball cleaning for the turbine condensers. The auxiliary cooling needs (generator, turbine lub. oil system and boiler plant miscellaneous users) are served by a closed loop system. That is connected to the main cooling water circulation system through plate type heat exchangers (2 x 100 % capacity). That arrangement secures trouble free operation and the cleaning of the intermediate exchangers can be done while the plant is at its full power.



4 BALANCE OF PLANT

4.1 Lignite Supply The lignite demand of the plant in tons/hr is as follows and the required transfer conveyor capacity:

Unit/plant size Average Worst fuel conveyors

500 MW unit 520 710 1500 750 MW unit 780 1070 >2000

2000 MW plant 2100 2800 >5000

The mining operator will deliver the lignite to the “gate of the power plant” i.e. the lignite comes on a belt conveyor (2 x 3500 t/h or one single conveyor >5000 t/h). The maximum incoming particle size is 300 mm i.e. the first operation at the power plant is to take it through an intermediate crushing plant. That operation reduces the maximum particle size down to 30-40 mm for stockpiling. There will be two/three crushers of 3500 t/h capacity, most probably with screens prior to them to by-pass the crushers with fine fraction of the lignite.

Figure 4-1 Schematic arrangement of lignite yard operation.

The fuel supply system from the mine is assumed to be reliable but a storage yard of capable to hold for 14 days´ full load consumption is outlined i.e. 175.000 tons per 500 MW and 700.000 tons for the whole plant. Typically the piles have a width of 45 meters with a maximum height of 16 meters. A pile with those dimensions can hold 400 tons/m i.e. for 175.000 tons (500 MW unit size) some 450 meters long pile is required. The total pile length would be 1800 meters for the 2000 MW plant.

Lignite from Sibovc mineup to 5000 t/h, 300 mm max. sizealternatively 2 belts 3500 t/h each

Lignite pile good for 14 days consumption

By-pass allowing direct feed to boiler bunkers

Boilers

Stacker

Reclaimer

< 40 mm size



Depending on the space available at the site each unit may have either one single 450 m long stockpile or two shorter piles.

One stacker-reclaimer is proposed for each generating unit. One stacker-reclaimer can serve two piles at a time, one pile on both sides of the stacker-reclaimer line as the sketch below illustrates. Figure 4-2 Pile arragengement for a 500 MW unit with one stacker-reclaimer.

The conveyor – crusher – stacking capacity is selected in the following way: If the power plant is operating at full load with the average heating value of the fuel the lignite stockpile can be filled up within two weeks. Even with the worst quality lignite the fill up time will not exceed 4 weeks. In the CFB boiler case there is a screening and crushing station before the conveyor leading to the boiler bunkers. The plant is dimensioned to be 2 x 2500 tph units that deliver an average/maximum particle size of 1 mm / 10 mm. In normal operation only one crusher unit is used and one is at stand by for failure of one unit or need of higher capacity when filling up the boiler silos. The experience of the Kosovo B power plant is that the lignite has tendency of arching in the boiler fuel silos and therefore special care has to be paid on the design and material selections of the silos and their cones.

4.2 Ash Systems The ash disposal system is basically the same for all the investigated unit concepts. The following diagram illustrates the configuration for pulverized fired units with wet slag conveyor under the furnace:

Pile 45 x 450 m or

2 x 45 x 230 m for 175.000 tons



Fly ash collectionby pneumatic system

Furnace slagwet conveyor

Dry ash equalizingbin

Mixing tanks withcirculation

Water from cooling tower

Dense phase ash & slagtransport system PF-boilers

Water to solids ratio ~1:1

To ash dumpin Mirash

Emergency flushing

Potential fly ash sales

Figure 4-3 Ash disposal systemp of the PF-boilers.

Correspondingly the system would look like the one below for CFB-fired boiler:

Fly ash collectionby pneumatic system

Bottom ashcooled conveyor

Dry ash equalizingbin

Mixing tanks withcirculation

Water from cooling tower

Dense phase ash & slagtransport system CFB-boilers

Water to solids ratio ~1:1

To ash dump

Emergency flushing

Potential fly ash sales

Figure 4-4 Ash disposal system of CFB fired boiler.

Dense phase ash and slag transportation system is proposed. The system mixes ash and crushed slag with water into a slurry in solids to water ratio 1:1. It is found that the resulting slurry is solidifying at the dump and very little of excess water or none is



released from the dump. The system is using conventional centrifugal pumps. It is expected that the system will be configured redundant in a such way that continuous transportation of fly ash or slag is guaranteed – no intermediate stockpiling required.

In case of selling fly ash for industrial use more stockpiling capacity may be required to hold the ash for quality control before its delivery.

For large fly ash collection systems pneumatic conveying with transmitters are used as there are numerous collection points under the electrostatic precipitator hoppers and below the air preheater outlet ducts. The fly ash silo has just a sufficient capacity of few hours to equalize the ash flow to the dumping area.

A wet slag conveyor is used to capture slag from the furnace. It will be equipped with a crusher before the slag is introduced into the slurry mixing tank. In case of CFB-boilers water cooled screw conveyors are used for the bottom ash. Those can feed the ash directly into the slurry mixing tank.

Blow down water of the evaporative cooling tower is used for fluidizing the ash in the mixing tanks.

4.3 Water Treatment The units are estimated to need the following average amounts of raw water:

500 MW PF 1364 m3/h (379 l/s)

500 mW CFB 1287 m3/h (358 l/s)

750 MW PF 2050 m3/h (569 l/s)

The fully developed 2000 MW plant would need 5150 – 5450 m3/h (1,4-1,5 m3/s) water. CFB-boiler based concept is using little less fresh water as there is no wet flue gas desulphurization plant.

In the contracting phase with the water supplier a certain safety margin have to be added to these figures.

The power plant will receive raw water either from the Ibër-Lepenc system or from the rivers Batlava or Lap (in case that existing Kosovo A supply system is used) as the map illustration below indicates.



Gazivodo LakeGood quality raw water available350 million cubic meters holding volume>10 cu.m/s average run off

Kosovo B

Kosovo A

Iber Lepenc IrrigationChannel system, 52 kmto Obeliq (Kosovo B)

Diversion to supplyCity of Pristine, <3,1 m3/s

City of Pristine

River Sitnica

to Feronikel

River Lab

River Batlava

Pumphouse at Brukovc>2,0 m3/s available

Bivolak

Figure 4-5 Map of the water systems.

The water treatment system is basically as the following diagram illustrates:

Batlava /LapRivers

(Kosovo A)

Iber-LepencKosovo B/Bivolak

Alternative sources:

Intake screenpumps

Intake screen(pumps)

Settling basin

Settling basinPlant raw/firewater storage10.000 cu.m

Process Firewater

Figure 4-6 The principle of the water treatment system.

The existing Kosovo B water supply from the Iber-Lepenc channel comes by gravity (about 1 km) as the channel is at a higher elevation than the water plant itself.

Kosovo B is using lime for softening the raw water for its cooling tower but it is recommended to use acid (HCl) regenerated softeners for that service and get rid of the lime sludge problems.

The boiler water has to be demineralised but its average consumption is very low, typically 1-2 % of the steam generation i.e. 3-5 kg/s (10-20 t/h). Especially in case of



supercritical boilers as there is no continuous blow down the consumption is low but the quality requirements are high.

A typical water treatment plant designs are illustrated below:

Mixing flocculants

Clarifier

Filtration

Filtered waterstorage tanks2 x 3000 cu.m

K

DemineralizingplantOther users

Cooling tower

Acid regeneratedsoftener withdegassifier

From Raw Water Supply

Sludge and backwashwater to waste treatment

Aluminiun sulphate orFerrichloride

Figure 4-7 The principle of a typical water treatment plant.

The demineralising plant is proposed to be as follows:

Demineralizedwater storage

tanks2 x 1000 cu.m

C1

C1 C2

c2 A1

A1 A2

A2

MB

HCl NaOHRegenerationNeutralization

Treated water

Demineralizedwater to process

to Waste water treatment

Degassifier



Figure 4-8 The principle of a demineralising plant.

The demineralised water storage tank is at least 1000 m3 and that should allow two start-ups without any additional waiting time. The demineralising plant continuous capacity is typically only 3-5 % of the steam generation i.e. 10-20 kg/s to cover the losses during the normal operation. The first unit would have two full capacity trains and thereafter the following units one full capacity train added.

The steam-water cycle has a condensate polishing plant of 2 x 50 %. That is basically a mixed bed ion exchange filter installation after the main condensate pumps. The water quality during normal operation is controlled with oxygen and ammonia. This system is widely used in supercritical intallations.

The preliminary water balances are illustrated in the following blockdiagrams.

Figure 4-9 Water balance 500 MW PF unit.



Figure 4-10 Water balances 500 MW CFB-plant above and 750 MW PF below.



Figure 4-11 Cost of water.

Some doubts have been raised on the availability of raw water and its use for large scale power generation. One way of saving water would be to switch to dry cooling i.e. Heller type cooling tower. In this concept the turbine surface condenser is replaced by a direct contact spray condenser and the circulation water is cooled in large vertical radiators. Those are placed around the bottom of natural draft cooling tower shell. The cooling effect is based on the dry bulb temperature of the ambient air as the evaporative cooling tower base is the wet bulb. There is a certain loss of capacity while applying dry system and that is estimated to be around 10,5 MW for a 500 MW unit as an annual average provided that the plant otherwise is exactly the same. The power generating capacities of these cooling methods are illustrated in the following picture:

500 MW Plant capacity vs. ambient temperature

455,0

460,0

465,0

470,0

475,0

480,0

485,0

490,0

495,0

500,0

505,0

-10 -5 0 5 10 15 20 25 30 35

Ambient dry temeperature

Meg

awat

ts

Evaporative cooling All dry Heller

Figure 4-12 Capacity of the 500MW plant on fuction of ambient temperature.

There are some intermediate solutions to boost the capacity of the dry system closer to the evaporative system but they are not considered at this phase.

A single 500 MW unit is expected to save around 9 million cubic meters annually i.e. the whole plant could cut its water consumption by 36 million cubic meters from 44-45 million cubic meters.

The dry cooling system is is more expensive to construct as the following summary indicates. For wet cooling the water supply and treatment plants are clearly more expensive.



Table 4-1 Investment costs for 4 500 MW unit.

Investment costs 4 x 500 MWin million EUR Wet DryCooling system 64,0 120,0Civil works tower 21,0 30,0Water supply and cleaning 17,0 3,0Grand total process changes 102,0 153,0Additonal cost of plant capacity 0,0 0,0Grand total plant cost 102,0 153,0Difference 51,0 M€

25,5 €/kW

The operating costs and lost revenue are estimated as follows if the sales price is 50 €/MWh and the variable cost of generation is 12 €/MWh. The cost of CO2-ton is 20 €:

Table 4-2 Operation and maintenance costs.

O & M costs in M€ Wet DryLost revenue 0,00 12,54Add CO2 charge 0,00 6,67Raw water cost 6,46 0,97Water cleaning 2,57 0,51Tower water chemicals 4,25 0,00Maintenance 3,00 2,00Grand total 16,28 22,69Difference O&M 6,41 M€/aDifference in annual capital 51,0 5,1 M€/aGrand total difference 11,51 M€/a

The net present value of the saved water per cubic meter is calculated by applying 10 %/a discounting factor and 40 years life for this base load plant. The cost of “the saved water” is presented in the figure below as function of CO2-price and electricity sales price being the other variable.



Kosovo C Cost of saved w ater

0

10

20

30

40

50

60

70

80

90

0 10 20

CO2 cost in €/ton

sent

/cu.

m

40 €/M W h50 €/M W h

Figure 4-13 The cost of the saved water.

The figure illustrates that both CO2-price and electricity sales price have remarkable impact on the water price what the competing users should pay for this large quantity of raw water. Iber-Lepenc has indicated that there sales price for the new plant would be in a range of 10 sents per cubic meter. From the power plant investor´s point of view the evaporative cooling tower is the concept to apply.

4.4 Oil / Start-up Systems The plant needs heavy and light fuel oil storage tanks for start-ups and shutdowns. The following diagram (see next page) illustrates the complete system. Typically this type of base load plants use 0,1-0,2 % of their total fuel demand i.e. 1000 tons/a per 500 MW or even less.

Heavy fuel oil needs continuous heating and that steam is normally drawn from the turbine extractions when the plant is running. For start-ups steam from the auxiliary boiler is required and for its start-up light fuel oil or electric heater has to be used.

Light fuel oil, LFO is used for first ignition and to fill the lines for shutdowns. The consumption of the light fuel oil (diesel) is around 10 % of the use of heavy fuel oil.

For a black start capability a light fuel oil fired gas turbine is recommended for the first unit. It could be a reconditioned old unit as its running hours will not be high but its starting reliability will be of utmost importance.



PFBoiler

PFBoiler

LPBoiler36 t/h

140 °C140 °Cmake up water

>150 t/h

120 t/h

30 t/h

Blow downIn start up,

FW-pump

Gas turbine 40MWe

LFOLFOLFO

HFO5000 m3

HFO5000 m3

HFO5000 m3

start upelectricity use

G

x MW

G

x MW

G

x MW

Figure 4-14 The oil/back-up start system.

The power plant needs a LP-steam boiler for starting the main unit and for heating the facility in a case that it is down for any reason during cold weather conditions. Steam is required for combustion air preheating and providing deaerating steam to the main feed water tank. The capacities are just indicative and should be verified with the selected boiler.

In case of locating the new plant aside Kosovo B power plant it is advisable to draw the start-up and /or heating steam from that plant. In case of the black start gas turbine a heat recovery steam generator (HRSG) could be installed after the gas turbine. A 40 MW gas turbine can produce 15-25 kg/s (54-90 t/) LP-steam while operating at full power. That is more than enough to provide steam for start-up.



5 ELECTRICAL SYSTEMS Each power generating unit is basically independent and is blocked directly to the main 400 kV system of Kosovo as the following single line diagrams illustrate:

Figure 5-1 Single line diagram of the 500 / 750 MW units (for clarity reasons only two units shown with the black start generator and 110 kV back-up connection).

The complete single diagrams can be found in Enclosure 1 of this base line report.

The generator voltage is proposed to be 24 kV and it is connected through an enclosed bus duct to the step-up transformer. There is an unit breaker as the bus duct feeds also a three winding auxiliary transformer. Three winding transformer is proposed to feed separately boiler feed water pump drives at 10 kV and other auxiliaries at 10 kV.

The connection system at 400 kV level to the existing system is discussed and presented in Task 2 of this study work. There are different approaches depending on the location of the new power plant (Kosovo A or B or Bivolak).



Additionally the plant has a maintenance/start-up power supply at 110 kV from the existing system. In case to locate the plant aside Kosovo B the connection to its 110 kV start-up transformer is recommended.

The generators are dimensioned for 0,85 power factor and their preliminary capacities are:

500 MW units 623 MVA 750 MW units 950 MVA

All the generators are hydrogen cooled (stators may be water cooled). The cooling water design temperature is 35 °C (closed loop system).

The plant will have the following voltage levels:

Transmission 400 kV Maintenance/start-up (110 kV) Generator 24 kV BFW-pump drives 10 kV MV 10 kV LV 690 V Service 400 V DC 220 V 24 V The unit auxiliary power system is configured into two sections fed by the separate windings of the auxiliary transformer but the systems have tie-breakers to have back-up capability. The concept is presented in a unit single line diagram in Enclosure 1. The units are connected to each other to furnish sufficient back-up service as the capacity of the unit auxiliary transformer would be extremely large for serving two units simultaneously while the other transformer is out of service. A black-start gas turbine is recommended to be able to get the plant up in case of the grid failure. The plant has a small diesel generator to provide back-up power for the control and supervisory systems, for safe shutdown of the plant as well as for the emergency lighting of the plant area.



6 AUTOMATION The plant will have modern digital distributed control system to supervise and control various systems of the plant. It will also incorporate all the necessary safety features (steam turbine & generator, burner management and boiler protections etc.). The hierarchical structure of the system is illustrated in the following picture:

M XM XX

MCC

Process

Drive Control LevelSingle drive ControlsClose Loop Controls

Sub-group Controls

Group Controls

Unit Controls GT1/HRSG1 GT2 /HRSG1 Steam Turbine

Block Control Block Coordinator

Protections

Functional Hierarchy

Operator access

M XM XX

MCC

Process

Drive Control LevelSingle drive ControlsClose Loop Controls

Sub-group Controls

Group Controls

Unit Controls GT1/HRSG1 GT2 /HRSG1 Steam Turbine

Block Control Block Coordinator

Protections

Functional Hierarchy

Operator access

Figure 6-1 The hierarchical structure of the distributed control system.

On the top of the above system there will be power dispatching communicating with the Kosovan TSO and all the internal management reporting and supervisory systems of the power company. A more detailed architecture of the automation system for different boiler concepts are presented in Enclosure 1 of this report.

The control room would have the following displays and keyboards for each unit:



Figure 6-2 The control room displays and keyboards (per one unit).

The field instruments are intelligent and are executed by using HART protocol. Most critical items are executed by using 2/3 concept.

The supercritical units are operated with gliding pressure principle whenever they are required to run at partial loads.

The plant overall control system and the turbine process will also have possibility to have running reserve capability by abruptly shutting down the condensate preheating and increase the turbine power to stabilize the grid. The exact requirements should be coordinated with TSO.

The emission measuring and recording system will be in full compliance with the European standards.



7 CIVIL STRUCTURES The preliminary lay-outs of the power plant are presented in Enclosure 2. There are general space requirements in more details for one unit (either PF or CFB boilers) and more specific site plans for each potential site. A space for a potential CO2-capture facility by using amines is also indicated aside of each unit. The potential sites are Kosovo A, B and Bivolak. The first unit would also need for the new raw water treatment facilities (flocculation, filtration plant and demineralization plants).

All the potential sites are close to the lignite pinch line or over the lignite deposit. The soil quality is clay overburden as described in details in the mine development reports. There is a seismic risk and the foundation system needs to be integrated i.e. the plant/unit will be placed onto a single reinforced concrete slab immersed into the ground well above the lignite seam in the same manner as Kosovo B has been constructed.

The structures are conventional: the boilerhouse is made of structural steel with weather enclosure walls of corrugated painted/plastic covered steel panels. The turbine house is also of steel frames with reinforced concrete slab as the main operating floor. The turbine pedestal is a reinforced concrete separate structure from the building or alternatively the whole turbine building is integrated and the turbine slab is supported by springs on that structure. The spring structure allows more space around the turbine and from the seismic resistance point of view would be better than a separate pedestal from the ground.

The evaporative cooling tower is a slip-formed reinforced concrete structure supported by a solid concrete slab that serves also as the water basin of the tower. The cooling water channels are either made of reinforced concrete or steel pipes in concrete culverts due to their size (> 2,3 m in diameter or two 1,7m).

The lignite yard has the concrete/steel supporting structures for the belt conveyors, stacker-reclaimers and possible retaining walls. The drainage from the lignite stockpile area is passed through a sedimentation basin before releasing the waters to the recipient stream.

Special care has to be paid onto the surface treatment/painting or material selection of the structures outdoors.

The power plant area floor drains and rain waters are separated as far as possible. The floor drains are passed through oil traps. The rainwaters from the roofs and open areas are collected to a central location and discharged trough a settling basin. Specific effluents (from FGD and raw water treatment plants) are piped separately to their treatment plants before releasing those waters to the Sitnica river.

The spaces for electrical and control equipment are furnished with air conditioning and their make-up air is filtered for added reliability. Those rooms are slightly pressurized.



Special emphasis is paid onto fire prevention / minimizing the effects of a fire by separation of spaces. The electrical and cable culverts/spaces are provided with automatic fire detection and extinguishing systems. The transformers are located in protective concrete enclosures and provided with sprinklers and oil catchment traps.

The oil receiving and oil tank yard will be walled and floor paved to catch possible spills. The rain waters are passed through an oil separation tank.

The control room and offices of the operating team in the power plant building are located in structures entirely separated from the main buildings in order to minimize the effects of vibration and noise. The same applies to laboratory for the fuel and waters and local small maintenance spaces.



8 PERFORMANCE OF THE PLANT The plant performance has been established for each of those three alternative concepts. The auxiliary power demand is estimated as follows:

Table 8-1 The auxiliary power demand.

Unit Size /Concept Alternative PF CFB PFkW kW kW kW kW kW

Gross generation 531000 533000 796000Boiler plant 18 200 20 250 27 300 BFW-pumps Steam 15 565 15 624 23 347 Fuel system 4 673 550 7 009 Fans 8 021 17 179 12 031 ESP & FGD 4 000 1 500 6 000 Misc. 1 506 1 021 2 259Turbine plant 1 250 1 250 1 875Coal handling 1 005 1 360 1 507Water treatment 635 635 952Cooling water circulation 4 380 4 380 6 569Compressed air 700 600 1 050Ash pumping 700 700 1 050Miscellaneous 1 500 1 500 2 250Total power plant auxiliaries 28 369 28 369 30 674 30 674 42 553 42 553Transformer losses 2 237 2 237 2 255 2 255 3 354 3 354Auxiliary power total 30 606 32 929 45 907

Net at 400 kV 500 394 500 071 750 093Auxiliary power percentage % 6,1 6,6 6,1

The CFB fired boiler has slightly higher power consumption than the PF-boiler due to the extensive fan power requirements. That difference is 0,5 percentage points in the plant gross power.

The plant overall efficiency calculation in MW can be done as follows:

Alternative 500 PF 500 CFB 750 PF Net power 500,0 500,0 750,0

Heat in steam-water 1108,9 1113,1 1632,2 Boiler losses, stack 55,6 55,7 83,4 , radiation 5,5 5,5 8,0 , UBC 12,0 12,1 17,5 Grand total heat release 1182,0 1186,4 1741,1 Efficiency % 42,3 42,1 43,0

The crucial issues in improving the overall efficiency are: auxiliary power demand and how the excess heat content of the wet flue gases is utilized for feed heating and air heating.

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