boiler T

482.8 Mkcal/hr 420 Mkcal/hr 180.6 Mkcal/hr 172 Mkcal/hr

200 MW120.7 t/h4000 kcal/kg

87.0 %

37.4%

35.6 %

43.0 %2000 kcal/kwhr

2299 kcal/kwhr

2414 kcal/kwhr

auxpower 10 MW

PLANT EFFICIENCY & HEAT RATE

210 MW

Heat Balance for Steam Process

Steam Process

Energy InputFeed Water

Energy InputAir & Fuel

EnergyLossFlueGas

EnergyLossBlow DownWater

EnergyLossDue to PipingFriction LossEquipment etc.

Steam @ PressureP1

P1

Usefull EnergyOutput

Energy Output = Energy Input - Losses

BOILER EFFICIENCY TEST

METHODS:

Direct Method

In-direct Method

Codes Being followed:

ASME PTC 4 – 1998

BS 2885 (revised as BS EN 12952-15:2003)

IS 8753 / 1977

DIN 1942

ISO R 889 / 1968

DIRECT METHOD

Efficiency = Output / Input

= Heat absorbed by working fluid * 100

(Heat in Fuel + Heat Credits)

Heat Credits

Heat in entering air

Heat in Atomizing steam

Sensible heat in fuel

Pulverizer power

Boiler Circulating water pump power

Heat supplied by moisture in entering air.

DIRECT METHOD

ADVANTAGES DISADVANTAGES

1. Based on the definition 1. Flows (Feed water & Fuel) of Efficiency. Should be measured very accurately.

2. Very less no of readings 2. Less accuracy

3. Capacity and output data 3. Identifying and correction also can be checked to the losses area is not possible.

4. Does not provide for corrections of

test results to Standards or Guarentee conditions.

INDIRECT METHOD (HEAT LOSS METHOD)Efficiency = 100 – (Heat Losses * 100)

(Heat in Fuel + Heat Credits)Heat Losses

Unburnt carbon loss

Dry gas loss Fuel hydrogen loss Fuel moisture loss Air moisture loss Carbon mono oxide loss Radiation and convection loss Sensible heat loss in fly ash Sensible heat loss in bottom ash Mill reject loss Heat credits (As Negative Loss)

INDIRECT METHODADVANTAGES DISADVANTAGES

1. Accuracy is more 1. More no of readings

2. Identifying the losses & correction 2. Capacity and output data can to the losses area is possible not be checked.

3. The primary measurements (Fuel, 3. Some losses are practically FG analysis & Temp) can be immeasurable and value measured very accurately.

must be estimated.

4. The resulting efficiency usually has lower uncertainty because the measured quantities (Losses) represents only a small fraction of the total energy.

5. The effects of fairly substantial errors in secondary measurement and estimated values are minimal.

6. Permits corrections of test results to standards or Guarantee condition.

Probable measurement errors and resulting errors in efficiency calculation by Direct method:

Measurement Measurement error Error in Effy

Calibrated Flow Nozzle ±0.55 ± 0.55

Coal Scales ± 0.25 ± 0.25

HHV (Coal) ± 0.50 ± 0.50

(Oil & Gas) ± 0.35 ± 0.35

Reheat flow (By Calculation) ± 0.60 ± 0.10

SH Outlet Temperature ± 0.25 ± 0.15

RH In / Out Temperature ± 0.25 ± 0.10

FW Temperature ± 0.25 ± 0.10

SH Outlet Pressure ± 1.00 ± 0.00

RH In/Out Pressure ± 0.50 ± 0.00

Probable measurement errors and resulting errors in efficiency calculation by Heat Loss Method:

Measurement Measurement error Error in Effy

HHV (Coal) ± 0.50 ± 0.03

(Oil & Gas) ± 0.35 ± 0.02

Orsat Analysis ± 3.00 ± 0.30

Exit Gas Temperature ± 0.50 ± 0.02

Inlet Air Temperature ± 0.50 ± 0.00

Ultimate Analysis

Carbon ± 1.00 ± 0.10

Hydrogen ± 1.00 ± 0.10

Moisture ± 1.00 ± 0.00

L2 Moisture loss % 6.523L1 Dry gas loss % 5.542L3 Combustible loss % 1.453

13.518L5 Radiation loss % 0.270L4 Air moisture loss % 0.200L6 Sensible heat of ash % 0.415L8 Carbon monoxide loss % 0.065L7 Mill reject loss % 0.049

0.999

L Total % 14.517

E Efficiency % 85.483100 - L

Summary of losses in a boiler

controllableL1 Dry gas loss % 5.542L3 Combustible loss % 1.453L8 Carbon monoxide loss % 0.065L7 Mill reject loss % 0.049

7.109

un -controllableL2 Moisture loss % 6.523L5 Radiation loss % 0.270L4 Air moisture loss % 0.200L6 Sensible heat of ash % 0.415

7.408

L Total % 14.517

E Efficiency % 85.483100 - L

Summary of losses in a boiler

1. UNBURNT CARBON LOSS

Ash in coal A % 43.96

% Carbon in fly ash Cf % 0.56Distribution of fly ash Df % 90Combustibles in fly ash Uf Kg / kg coal 0.00223 Uf = Df/100 * A/100 * Cf / (100 - Cf)

% Carbon in bottom ash Cb % 3.26Distribution of bottom ash Db % 10Combustibles in bottom ash Ub Kg / kg coal 0.00148 Ub = Db/100 * A/100 * Cb / (100 - Cb)

Total combustibles U Kg / kg coal 0.00371 U = Uf + Ub

CV of Carbon CVc Kcal / kg 8077.8GCV of coal Gcv Kcal / kg 3627.84

Unburnt carbon loss L_UC % 0.826 L_UC = U * CVc * 100 / Gcv

2. DRY GAS LOSS

Carbon in coal C % 34.32Sulphur in coal S % 0.43Total combustibles U Kg / kg coal 0.00371Specific heat of gas Cp KJ / kg mol / °C 30.6FG temp. at AH outlet Tg ° C 138Ref. air temp. Ta ° C 43CO2 % at AH outlet CO2_out % 14.5CO % at AH outlet CO_out % 0.05GCV of coal Gcv Kcal / kg 3627.84Weight of dry gas per Kg of Wd Kg / kg mol 0.1953 "as fired fuel" ( C + S / 2.67 - 100 * U ) 12 * (CO2_out + CO_out)Sensible heat of dry gas Sh KJ / kg coal 567.64 Sh = Wd * Cp * (Tg - Ta)

Dry Gas loss L_G % 3.738 L_G = Sh * 100 / Gcv / 4.186

3. LOSS DUE TO MOISTURE IN FUEL

Total moisture in fuel M % 8FG temp. at AH outlet Tg ° C 138Ref. air temp. Ta ° C 43GCV of coal Gcv Kcal / kg 3627.84Sensible heat of water vapour Sw KJ / kg 2578.84 SW = 1.88 * (Tg - 25) + 2442 + 4.2 * (25 - Ta)

Loss due to moisture in fuel L_M % 1.358 L_M = M * Sw / Gcv / 4.186

4. LOSS DUE TO HYDROGEN IN FUEL

Hydrogen in coal H % 1.96

Loss due to hydrogen in fuel L_H % 2.997 L_H = 9 * H * Sw / Gcv / 4.186

5. LOSS DUE TO MOISTURE IN AIR

Carbon in coal C % 34.32Hydrogen in coal H % 1.96Sulphur in coal S % 0.43Oxygen in coal O % 6.02GCV of coal Gcv Kcal/kg 3627.84Ambient temp. (dry) Td ° C 40Ambient temp. (wet) Tw % 32Wt. of moisture Mwv Kg/kg air 0.0273 (from psychrometric chart)Ref. air temp. Ta ° C 43FG temp. at AH outlet Tg ° C 138O2 % at AH outlet O2_out % 4.6CO2 % at AH outlet CO2_out % 14.5CO % at AH outlet CO_out % 0.05N2 % at AH outlet N2_out % 80.84 N2_out = 100 - (O2_out + CO2_out + CO_out)Stoichiometric air Sa Kg / kg coal 4.3702 Sa = (2.664*C + 7.937*H + 0.996*S - O) / 23.2Excess air Ea % 26.743 Ea = (O2_out - CO_out/2) / [0.2682*N2_out - (O2_out - CO_out/2)] * 100Total moisture in air Ma Kg / kg 0.1512 Ma = Sa * Ea * Mwv

Loss due to moisture in air L_mA % 0.178 L_mA = Ma * 1.88 * (Tg - Ta) * 100 / Gcv / 4.186

6. LOSS DUE TO CARBON MONOXIDE

CO2 in gas - AH out CO2_o % 12.2CO in gas - AH out CO_o % 0.0085Carbon in fuel C % 40.8654CV of carbon monoxide CVco Kcal/kg 2415Gross CV Gcv Kcal/kg 3620Combustibles U Kg/kg of coal 0.005686

Loss due to carbon monoxide L_co % 0.044

L_co =CO_o*7*CVco*(C-100U)/3/(CO2_o+CO_o)/Gcv

7. RADIATION LOSS

Loss due to surface L_ß % 0.22radiation and convection (as per prediction based on ABMA curve)

8. LOSS DUE TO SENSIBLE HEAT IN FLY ASH

Temperature of fly ash Tg ° C 138Ref. air temp. Ta ° C 43Specific heat of fly ash Cpf Kcal / kg / °C 0.16Ash in coal A % 43.96Distribution of fly ash Df % 90GCV of coal Gcv Kcal / kg 3627.84

Loss due to sensible heat in fly ash L_f % 0.166 L_f = A/100 * Df/100 * Cpf * (Tg - Ta) * 100 / Gcv

9. LOSS DUE TO SENSIBLE HEAT IN BOTTOM ASH

Temperature of bottom ash above ambient Tb ° C 600Specific heat of bottom ash Cpb Kcal / kg / °C 0.16Ash in coal A % 43.96Distribution of bottom ash Db % 10GCV of coal Gcv Kcal / kg 3627.838

Loss due to sensible heat in bottom ash L_b % 0.116 L_b = A/100 * Db/100 * Cpb * Tb * 100 / Gcv

Heat Credits:

The heat crdits are generally the other heat inputs then through / from the fuel. (eg. Heat due to shaft power of pulverizer, Fans, etc. which are coming inside the system boundary)

10. HEAT CREDIT

Total Mill power MP Kw 2475Total PA Fan power Kw 956.25Total coal flow Cflo T/hr 100.9GCV of coal Gcv Kcal/kg 3627.84Kw-hr / kg of fuel KwKg Kw-hr/kg 0.034006 KwKg = MP / Cflo / 1000

Heat credit (Heat Equivalent of Power) H_cr % -0.806 (as negative loss) H_cr = KwKg * 859.86 * 100 / Gcv

Various Boiler Losses

By Gas Dry Gas Loss

Loss due to Moisture in Gas

Due to Fuel Moisture

Due to moisture formed by H2 in fuel

Due to air moisture

By Ash Unburnt carbon Loss

Sensible heat loss in Fly ash

Sensible heat loss in Bottom ash

Other Loss Carbon mono oxide Loss

Radiation Loss

Heat loss through Mill rejects

Heat Credit

Factors affecting Unburnt Carbon Loss

a) Design Factors

Type of fuel preparation system

Burner and Burning System

Residence time

b) Fuel Characteristics

Heating Value

Proximate Analysis

Ultimate Analysis

c) Operational facors

Coal Particle Size

Excess air

Primary air to coal ratio

Distribution of Secondary air

Burner Tilt

Air Temperature

Factors Affecting Dry Gas Loss

1 CoalMoistureCarbon Gross CV

2 Air temperature entering AHAmbientSCAPH

3 Gas temperatureAH leakageAH entering air temperatureAH entering gas temperature

Boiler loadFW temperature

X ratio of AHTempering air Air ingress

4 Gas quantityExcess airAH leakage

Factors Influencing Various Losses

01. Dry Gas Loss

Flue Gas Temperature, Excess Air & Fuel Analysis

02. Loss Due To Moisture Formed From Hydrogen

Hydrogen Content In Fuel & Flue Gas Temperature

03. Loss Due To Fuel Moisture

Moisture Content In Fuel & Flue Gas Temperature

04. Loss Due To Air Moisture

Humidity Of Combustion Air, Excess Air Level & Flue Gas Temperature

Factors Influencing Various Losses

05. Radiation & Convection Loss

Insulation Of Boiler

06. Mill Reject LossReject Rate & CV Of Reject

07. Unburnt Carbon Loss In AshAsh in Fuel & Unburnt Carbon In Fly / Bottom Ash

08. Sensible Heat Loss In AshAsh Temperature

Capacity Reduction in a Boiler

Fuel inputLow cv coalMilling capacity

Grinding capacityDrying capacityCarrying capacityDrive capacity

Draught systemID fan limitations

Pressure drops highAH chokingChimney back pressure high

High volumeAH leakagesDuct leakagesHigh gas temperatures

Worn out impellers

Metal temperatures highHigh spray requirementsFouling of surfaces

• Good burner maintenance• Ensuring consistent mill fineness• Proper secondary air adjustment• Reducing primary air to the minimum most possible• Cutout oil support at higher loads where coal flame is

stable as oil preferentially deplete o2 in the area and reduces ‘o2 ‘ for coal particles to burn

• Check coal property and tune combustion• Keep boiler heat transfer surface clean so that losses can

be reduced thus reducing the coal input

METHODS OF REDUCTION OF METHODS OF REDUCTION OF UNBURNT CARBON LOSSUNBURNT CARBON LOSS

UNBURNT CARBON LOSS CAUTION

IT ALSO DEPENDS ON• COAL PROPERTIES LIKE VOLATILE

MATTER AND FIXED CARBON TO VOLATILE MATTER RATIO.

• FURNACE SIZE• TYPE OF MILL AND FIRING SYSTEM• SUPPLEMENTRY FUEL FIRING LIKE

BFG GAS ,COG GAS or COREX GAS

METHODS OF REDUCTION OF DRY GAS LOSS

- CORRECT EXCESS AIR

- HIGH MILL OUTLET TEMP.

- ARRESTING AIR INGRESS

- AIR HEATER PERFORMANCE

- CLEAN SURFACES

- SEAL/COOLING/PURGE

AIR QTY. JUST REQD.

Flue Gas Temperature Reduction methods

• Operate the boiler at correct excess air. (Usually 20 % for coal)

• Cleanliness of boiler surfaces• Good combustion of fuel• Reduction of tempering air to mill.• Reduction in air ingress• Cleaning of air heater surfaces and

proper heating elements

Boiler Efficiency Calculation – Direct Method (Input/Output Method)

Efficiency, E = Ho/Hi*100Where,

Heat Input, Hi = CF * GCV*1000

Heat Output, Ho = {Qf*(Hs – Hf) + Qr*(Hro – Hri)}*1000

Where,

CF – CoalFlow; Qf – FW Flow quantity

Hs – SH Outlet Enthalpy; Hf – FW Enthalpy

Qr – RH Flow; Hro - RH Outlet Enthalpy

Hri - RH inlet Enthalpy

APH Performance (Code: ASME PTC 4.3)

APH Leakage in %, AL = (Wg – Wgi)*100 / Wgi

= (CO2_in – CO2_out)*90 / CO2_out OR = (O2_out – O2_in)*100 / (21 – O2_out)

TgNL = AL / 100 * CpA / CpG*(Tgo – Ta) + Tgo

Gas side efficiency, Ef_G = (Tgi – TgNL)*100 / (Tgi – Ta)

X Ratio, XR = (Tgi – TgNL) / (Tao – Ta)

Tgc = {Tac*(Tgi – Tgo) + Tgi*(Tgo – Ta)} / (Tgi – Ta)

Where

Tgi & Tgo – Gas temperature entering & leaving APH

Ta & Tao – Air temperature entering & leaving APH

Tac – Design air temperature entering APH

TgNL – Calculated Gas temperature leaving APH corrected for No air leakage

Tgc – Corrected gas temp leaving APH for deviation from design entering air temp

CpA & CpG – Mean Specific heat of air and gas

Wgi & Wg – Quantity of wet gas entering & leaving APH

NOx Conversion:

NOx (in Kg/GJ) = NOx (in PPM) * 0.718 / 1000 * (21 – O2ref) / (21 – O2)

Performance Calculations1. SH Spray Flow = FW Flow*(h_SHBS – h_SHAS) / (h_SHBS–h_SHSW)

2. RH Spray Flow = RH Flow*(h_RHBS – h_RHAS) / (h_RHAS–h_RHSW)

3. FC = SH Flow*(h_SH-h_FW) + RH Flow*(h_Rho-h_Rhi)*100 GCV*Efficiency

4. Excess Air = (O2i-COi/2)*100 / {0.2683*N2i-(O2i-COi/2)} or

O2/(20.9-O2)

Where,

FC – Fuel consumption

h_SHBS – Enthalpy at SH before spray

h_SHAS – Enthalpy at SH after spray

h_SHSW – Enthalpy of SH spray water

RH flow calculation

Reheater Flow, Qr = Qs – Qgl – Qex + QrsWhere,

Qs – SH Flow; Qgl – Turbine gland leak flow

Qrs – RH spray flow; Qex – HP Heater 6 Extraction quantity

Qex = Qfw*(Hfwo – Hfwi) / (Hex – Hd)Where,

Qfw – FW flow

Hfwi – Feed water HP heater 6 inlet Enthalpy

Hfwo – Feed water HP heater 6 outlet Enthalpy

Hex – HP heater 6 Extraction Enthalpy.

Hd – HP heater 6 Drain Enthalpy.

Proximate to Ultimate Conversion

Proximate Data (As fired) Sample Total Moisture M % 8.00Ash A % 42.60VOLATILE MATTER VM % 21.60FIXED CARBON FC % 27.80GCV GCV Kcal/Kg 3800.00

Proximate Analysis (On M & Ash Free basis)VM (M & Ash Free) VM' % 43.72FC ( M & Ash Free) FC' % 56.28VM'=VM*100/(100-VM-A)

Ultimate Analysis (On M & Ash Free basis)Carbon C' % 79.43

Hydrogen H' % 5.41

Sulphur S' % 1.00Nitrogen N' % 1.58N' = 2.1 - 0.012*VM'Oxygen O' % 12.58O' = 100 - (C' + H' + S' + N')

Ultimate Analysis Carbon C % 39.24Hydrogen H % 2.67Sulphur S % 0.49Nitrogen N % 0.78Oxygen O % 6.22

Moisture % 8.00Ash % 42.60

100.00

C' = FC' + 0.9*(VM'-18)

H' = VM' * {7.35 / (VM'+10) - 0.013}

C = C' * (100 - M - A) / 100

Sl.No Description Symbol Unit1 Turbine Heat rate THR Kcal/KWHr 2000 2000 20002 Boiler Efficiency BE % 86 87 883 Change in Boiler Efficiency CBE % -1 0 14 Plant Heat rate PHR Kcal/KWHr 2325.58 2298.85 2272.73

(PHR = THR / BE *100)5 Change in plant heat rate CPHR Kcal/KWHr -26.73 0.00 26.12

For 200MW Unit with 75% PLF6 Units generated per year UG KWHr 1314000000 1314000000 1314000000

(UG = 200*24*365*0.75*1000)7 Heat required per year HR Kcal 3.05581E+12 3.0207E+12 2.9864E+12

(HR=UG*PHR)For coal of 4000 Kcal/Kg

8 Coal qty required CQ Tonnes 763953.4884 755172.414 746590.909(CQ = HR / 4000 / 1000)For coal cost of Rs.1000 / Ton

9 Total cost of coal CC Rs 763953488.4 755172414 746590909(CC = CQ * 1000)

10 Change in cost CIC Rs -8781074.58 8581504.7011 Change in cost per Unit Heat rate CICHR Rs 328500 328500

(CICHR = CIC / CPHR)12 Change in cost per Unit Efficiency CICE Rs -8781074.579 8581504.7

(CICE = CIC / CBE)13 Unit cost of power CP Rs 0.5814 0.5747 0.5682

(CP = CC / UG)For 1 KW Auxiliary Power

14 Units lost per year UL 8760 8760 8760(UL = 1*24*365)

15 Cost per year C 5093 5034 4977(C = UL*CP)

SH outlet pressure

SH outlet temperature

RH outlet temperature

RH spray

SH spray

Blowdown

Auxiliary Steam

Effect of boiler parameterson thermal cycle

kcal/hr10 ° C drop in MS temperature 9.6

10 ° C drop in RH outlet temperature 6.6

1 % increase in RH pr. drop 3(% of inlet pr.)

Decrease in throttle pressure by 1 bar 1.2

SH spray increase by 1 % 0.6

RH spray increase by 1 % 6

For a 500 MW unit

Effect on Plant Heat Rate Due to Boiler Parametars

Optimization of Boiler Efficiencya) HHV All Losses

b) FG APH out Temp Dry gas, Sensible heat in Ash, H2, Fuel and Air Moisture Loss

c) Excess air Dry gas, Unburnt & Air Moisture Loss

d) Fuel Moisture Fuel Moisture Loss

e) Air Moisture Air Moisture Loss

f) H2 in Fuel H2 Loss

g) Mill reject rate or GCV Mill reject Loss

Hence Major parameters to be looked into for Better Efficiency are

1. FG Temp

2. Excess air Level

3. Mill reject rate and

4. Unburnt carbon in ash

Control / Optimization of other parameters (i.e GCV, H2, Fuel moisture and Air Moisture) are not possible.

Correction of Efficiency to Standard / Guaranteed Condition.

Correction of Efficiency are done for Variation in Following Factors

GCV of Fuel

H2 in Fuel

Total Moisture in Fuel

Ambient temperature and

Humidity of air.

BOILER AUXILIARIES

-INDUCED DRAFT FAN

- FORCED DRAFT FAN

- PULVERIZER MILLS

- PRIMARY AIR FAN

-SEAL/PURGE/COOLING/ IGNITOR AIR FAN

- LUBRICATION OIL SYSTEMS

MAJOR REASONS OF INCREASE IN AUXILIARY POWER CONSUMPTION ARE

• OPERATION OF UNIT WITH HIGHER EXCESS AIR

• AIR INGRESS IN BOILER• AIR HEATER LEAKAGE• HIGHER PA FAN OUTLET PRESSURE• COAL PULVERIZATION TOO FINE • PLUGGAGE IN LINE

FACTORS AFFECTING AUXILIARY POWER

ID FANSAH LEAKGAS TEMPERATUREDUCT LEAKAGESEXCESS AIRLOAD/ PLANT HEAT RATEDRAUGHT LOSS

AH CHOKINGFD FANS

AH LEAKWIND BOX PR.EXCESS AIRLOAD/ PLANT HEAT RATEPRESSURE LOSS

AH CHOKINGSCAPH CHOKING

PA FANSAH LEAKAGEPA HEADER PR.MILL AIR FLOWPRESSURE LOSS

AH CHOKINGMILL

COAL QTY.GCVLOAD/ PLANT HEAT RATE

COALMOISTUREHGI

COAL FINENESSMILL CONDITION

SOURCES OF AIR INGRESS(MEMBRANE WALL BOILER)

• FURNACE ROOF• EXPANSION JOINTS• AIR HEATERS• DUCTS• ESP HOPPERS• PEEP HOLES• MANHOLES• FURNACE BOTTOM

TUBULAR AIR HEATER

• CLEANING OF TUBES

• REPLACING OF DAMAGED TUBES

• PROPER DISTRIBUTION OF GAS AND AIR

ROTARY AIR HEATERS

• PROPER BASKETS

• CLEANLINESS OF BASKETS

• PROPER SEAL SETTING

HIGHER PA OUTLET PRESSURE

• INCREASES AIR HEATER LEAKAGE RESULTING IN HIGHER ID FAN LOADING

• INCREASES PA FAN POWER CONSUMPTION

• MAINTAIN ADEQUATE PRESSURE

EXCESS MILL FINENESS

• REDUCES MILL CAPACITY

• INCREASES MILL WEAR

• INCREASE MILL AND PA FAN POWER

• MAY NOT IMPROVE COMBUSTION

METHODS TO REDUCE AUXILIARY POWER

- OPERATE UNIT AT CORRECT AIR FLOW

- AIR INGRESS REDUCTION

- AIR HEATER MAINTENANCE

- OPTIMUM FAN OPERATION

- RUN MIN. NO. OF MILLS REQD.

- PULVERIZER TO OPERATE AT CORRECT AIR FLOW AND PULVERIZED COAL FINENESS

- IMMEDIATELY ATTEND FUEL, AIR, WATER AND STEAM LEAKAGES.

TYPICAL HEAT LOSSUNIT DADRI SING EIDMW 200 500 16CARBON LOSS 0.827 0.364 0.52DRY GAS LOSS 4.325 4.847 5.320FUEL H2 LOSS 3.609 3.520 6.57FUEL MOISTURELOSS

2.129 2.814 15.99

OTHER LOSSES 1.001 0.726 0.44TOTAL LOSS 11.711 12.071 28.84FUEL COAL COAL BAGASSE