The Presentation discusses the Air-Heater Performance Indices and the Boiler Performance calculation. One can Calculate the air ingress in the air-heater and the boiler and losses incurred thereby. The presentation also describes in details about the boiler efficiency and its calculation.

1. Presentation Coverage
Air Heater & Boiler Performance Indices
Improvements in Measurements - Case
Studies
Calculation of Boiler Efficiency - Sample
Calculations
05/08/19 1Manohar Tatwawadi

2. Air Heater - Performance Indicators
• Air-in-Leakage
• Gas Side Efficiency
• Heat X - ratio
• Flue gas temperature drop
• Air side temperature rise
• Gas & Air side pressure drops
(The indices are affected by changes in entering
air or gas temperatures, their flow quantities and
coal moisture)
05/08/19 2Manohar Tatwawadi

3. AH Performance Monitoring
• O2 & CO2 in FG at AH Inlet
• O2 & CO2 in FG at AH Outlet
• Temperature of gas entering / leaving air heater
• Temperature of air entering / leaving air heater
• Diff. Pressure across AH on air & gas side
(Above data is tracked to monitor AH performance)
05/08/19 3Manohar Tatwawadi

4. Air heater Air-in-leakage
All units that operate with a rotary type regenerative air
heater experience some degree of air leakage across
the air heater seals.
An increase in air leakage across the seals of an AH
results in increased ID and FD fan power and flow rate
of flue gas. Sometimes it can put limitations on unit
loading as well.
Typically air heater starts with a baseline leakage of 8
to 10% after an overhaul.
05/08/19 4Manohar Tatwawadi

5. Air Heater Leakage (%)
The leakage of the high pressure air to the low
pressure flue gas is due to the Differential Pressure between
fluids, increased seal clearances in hot condition, seal
erosion / improper seal settings.
Increased AH leakage leads to
• Reduced AH efficiency
• Increased fan power consumption
• Higher gas velocities that affect ESP performance
• Loss of fan margins leading to inefficient operation and at
times restricting unit loading
05/08/19 5Manohar Tatwawadi

6. Air Heater Leakage (%)
• Direct - Hot End / Cold End
(60% through radial seals + 30% through Circumferential
bypass)
Air leakage occurring at the hot end of the air
heater affects its thermal and hydraulic
performance while cold end leakage increases
fans loading.
• Entrained Leakage due to entrapped air between
the heating elements (depends on speed of rotation
& volume of rotor air space)
05/08/19 6Manohar Tatwawadi

7. Rotary Air heater
RADIAL SEAL
AXIAL
SEAL
BYPASS SEAL
COLD END
HOT END
HOT INTERMEDIATE
05/08/19 7Manohar Tatwawadi

8. SEALS ARRANGEMENT
05/08/19 8Manohar Tatwawadi

9. Double seal
05/08/19 9Manohar Tatwawadi

10. Flexible seal assembly - Cold Condition
05/08/19 10Manohar Tatwawadi

11. Flexible seal assembly - Hot Condition
05/08/19 11Manohar Tatwawadi

12. Leakage Assessment
• Leakage assessment must be done by a grid survey using
a portable gas analyser.
• Calculation of leakage using CO2 values is preferred
because of higher absolute values and lower errors.
• Method of determination of O2 or CO2 should be the same at
inlet and outlet - wet or dry (Orsat)
• Single point O2 measurement feedback using orsat is on dry
basis while zirconia measurement is on wet basis.
• Leakage assessment is impacted by air ingress from
expansion joints upstream of measurement sections.
05/08/19 12Manohar Tatwawadi

13. Air Heater Leakage (%)
Weight of air passing from air side to gas side
This leakage is assumed to occur entirely between air
inlet and gas outlet
05/08/19 13Manohar Tatwawadi

14. Air Heater Leakage - Calculation
Empirical relationship using the change in concentration of
O2 or CO2 in the flue gas
= CO2in - CO2out * 0.9 * 100
CO2out
= O2out - O2in * 0.9 * 100 = 5.7 – 2.8 * 90
(21- O2out) (21-5.7)
= 17.1 %
CO2 measurement is preferred due to high absolute values;
In case of any measurement errors, the resultant influence on
leakage calculation is small.
05/08/19 14Manohar Tatwawadi

15. Gas Side Efficiency
Ratio of Gas Temperature drop across the air heater,
corrected for no leakage, to the temperature head.
= (Temp drop / Temperature head) * 100
where Temp drop = Tgas in -Tgas out (no leakage)
Temp head = Tgasin - T air in
Gas Side Efficiency = (333.5-150.5) / (333.5-36.1) = 61.5 %
05/08/19 15Manohar Tatwawadi

16. Tgas out (no leakage) = The temperature at which the gas
would have left the air heater if there were no AH leakage
= AL * Cpa * (Tgas out - Tair in) + Tgas out
Cpg * 100
Say AH leakage – 17.1%, Gas In Temp – 333.5 C, Gas Out Temp –
133.8 C, Air In Temp – 36.1 C
Tgasnl = 17.1 * (133.8 – 36.1) + 133.8 = 150.5 C
100
05/08/19 16Manohar Tatwawadi

17. HEAT X – Ratio
Ratio of heat capacity of air passing through the air heater to
the heat capacity of flue gas passing through the air heater.
= Wair out * Cpa
Wgas in * Cpg
= Tgas in - Tgas out (no leakage)
Tair out - Tair in
Say AH leakage – 17.1%, Gas In Temp – 333.5 C, Gas Out Temp –
133.8 C , Air In Temp – 36.1 C, Air Out Temp – 288 C
X ratio = (333.5 – 150.5) / (288 –36.1) = 0.73
05/08/19 17Manohar Tatwawadi

18. X-Ratio depends on
• moisture in coal, air infiltration, air & gas mass flow rates
• leakage from the setting
• specific heats of air & flue gas
X-ratio does not provide a measure of thermal performance
of the air heater, but is a measure of the operating
conditions.
A low X-ratio indicates either excessive gas weight through
the air heater or that air flow is bypassing the air heater.
A lower than design X-ratio leads to a higher than design
gas outlet temperature & can be used as an indication of
excessive tempering air to the mills or excessive boiler
setting infiltration.
05/08/19 18Manohar Tatwawadi

19. Pressure drops across air heater
• Air & gas side pressure drops change approximately in
proportion to the square of the gas & air weights through
the air heaters.
• If excess air is greater than expected, the pressure drops
will be greater than expected.
• Deposits / choking of the basket elements would lead to an
increase in pressure drops
• Pressure drops also vary directly with the mean absolute
temperatures of the fluids passing through the air heaters
due to changes in density.
05/08/19 19Manohar Tatwawadi

20. Air Ingress Calculations
Air ingress quantification is done with the same formulae
as those used for calculation of AH leakage
Air ingress
= O2out - O2in * 0.9 * 100 = 6.5 - 5.7 * 90
(21- O2out) 21 - 6.5
= 4.96 %
The basis of O2 or CO2 calculation should be the same –
either wet or dry.
05/08/19 20Manohar Tatwawadi

21. Air Heaters Temp measurements
• Thermocouples for flue gas temperatures at AH inlet as
well as exit are generally clustered on one side.
• A grid survey is needed for representative values.
• Exit gas temperatures need to be corrected to a
reference ambient and to no leakage conditions for
comparison.
• Thermocouples for SA temperature measurement at
AH outlet are mounted too close to air heaters and need
to be relocated downstream to avoid duct stratification.
• Additional mill or changes in coal quality change
thermal performance of a tri-sector air heater in a very
major way; performance evaluation is difficult.05/08/19 21Manohar Tatwawadi

22. Flue gas temperature as measured in common ducts leading
to ESPs in 500 MW units is more representative than weighted
averages of temperatures measured at individual AH exits.
Flue Gas Temperatures C
T 3 T 4 T 9 T 11 T 14
PAPH A Outlet 142.7 133.2 145.7 139.1 139.9
SAPH A Outlet 132.5 133.1 139.8 138.1 137.0
Eqv. Temp A side 135.9 133.1 141.7 138.5 138.0
Grid Average Left 141.8 146.5 147.3 144.1 143.6
PAPH B Outlet 142.2 134.5 143.9 137.9 149.5
SAPH B Outlet 135.9 132.4 139.6 136.2 143.2
Eqv. Temp B side 138.0 133.1 141.0 136.7 145.3
Grid Average Right 144.0 147.5 149.9 148.4 150.4
Flue Gas Temperature at AH outlet
05/08/19 22Manohar Tatwawadi

23. Boiler Performance
Boiler Efficiency
The % of heat input to the boiler absorbed by the
working fluid (Typically 85-88%)
05/08/19 23Manohar Tatwawadi

24. Boiler Efficiency…
Boiler Efficiency can be determined by
a) Direct method or Input / Output method
b) Indirect method or Loss method
05/08/19 24Manohar Tatwawadi

25. Direct Method
100
valuecalorificGrossxratefiringFuel
enthalpy)waterfeedenthalpy(steamxrateflowSteam
xEfficiencyBoiler
−
=
05/08/19 25Manohar Tatwawadi

26. Boiler Efficiency…
Direct method or Input / Output method measures the
heat absorbed by water & steam & compares it with
the total energy input based on HHV of fuel.
• Direct method is based on fuel flow, GCV, steam flow
pressure & temperature measurements. For coal
fired boilers, it’s difficult to accurately measure coal
flow and heating value on real time basis.
• Another problem with direct method is that the extent
and nature of the individual components losses is not
quantified.
05/08/19 26Manohar Tatwawadi

27. Boiler Efficiency…
Indirect method or Loss method
For utility boilers efficiency is generally calculated by heat
loss method wherein the component losses are calculated
and subtracted from 100.
Boiler Efficiency = 100 - Losses in %
05/08/19 27Manohar Tatwawadi

28. Indirect Method
Boiler Flue gas
Efficiency = 100 – (1+2+3+4+5+6+7+8)
Fuel + Air
1. Dry Flue gas loss
2. H2 loss
3. Moisture in fuel
4. Moisture in air
5. CO loss
7. Fly ash loss
6. Radiation
8. Bottom ash loss
WaterSteam
05/08/19 28Manohar Tatwawadi

29. Indirect or Loss method
• In Heat Loss method the unit of heat input is the higher
heating value per kg of fuel. Heat losses from various
sources are summed & expressed per kg of fuel fired.
Efficiency = 100 – (L/Hf) * 100
L – losses
Hf – heat input
05/08/19 29Manohar Tatwawadi

30. Indirect or Loss method
• This method also requires accurate determination of
heating value, but since the total losses make a relatively
small portion of the total heat input (~ 13 %), an error in
measurement does not appreciably affect the efficiency
calculations.
• In addition to being more accurate for field testing, the
heat loss method identifies exactly where the heat
losses are occurring.
05/08/19 30Manohar Tatwawadi

31. Boiler Efficiency…
Commonly used standards for boiler performance testing are
ASME PTC 4 (1998)
BS – 2885 (1974)
IS: 8753: 1977
DIN standards
05/08/19 31Manohar Tatwawadi

32. arameters required for computing Boiler Efficiency
AH flue gas outlet O2 / CO2 / CO
AH flue gas inlet and outlet temp C
Primary / Secondary air temp at AH inlet / outlet C
Total Airflow / Secondary Air Flow t/hr
Dry/Wet bulb temperatures C
Ambient pressure bar a
Proximate Analysis & GCV of Coal kcal / kg
Combustibles in Bottom Ash and Flyash
05/08/19 32Manohar Tatwawadi

33. Boiler Losses Typical values
Dry Gas Loss 5.21
Unburnt Loss 0.63
Hydrogen Loss 4.22
Moisture in Fuel Loss 2.00
Moisture in Air Loss 0.19
Carbon Monoxide Loss 0.11
Radiation/Unaccounted Loss 1.00
Boiler Efficiency 86.63
05/08/19 33Manohar Tatwawadi

34. Effect of Operating Parameters on Boiler Losses
05/08/19 34Manohar Tatwawadi

35. Dry Gas Loss (Controllable)
• This is the heat carried away by flue gas at AH outlet
• It’s a function of flue gas quantity and the temperature
difference between air heater exit gas temperature
and FD fan inlet air temperature
• Typically 20 C increase in exit gas temperature ~ 1%
reduction in boiler efficiency.
05/08/19 35Manohar Tatwawadi

36. Dry Gas Loss…
Sensible Heat of flue gas (Sh)
Sh = Mass of dry flue gas X Sp. Heat X (Tfg – Tair)
Dry Flue Gas Loss % = (Sh / GCV of Fuel) * 100
05/08/19 36Manohar Tatwawadi

37. Dry Gas loss reduction requires
• Boiler operation at optimum excess air
• 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 / surface area
05/08/19 37Manohar Tatwawadi

38. Unburnt Carbon Loss (Controllable)
• The amount of unburnt is a measure of effectiveness of
combustion process in general and mills / burners in
particular.
• Unburnt carbon includes the unburned constituents in
flyash as well as bottom ash.
• Ratio of Flyash to Bottom ash is around 80:20
• Focus to be on flyash due to uncertainty in repeatability
and representative ness of unburnt carbon in bottom ash
• +50 PF fineness fractions to be < 1-1.5%05/08/19 38Manohar Tatwawadi

39. Unburnt Carbon Loss (Controllable)
Loss due to Unburnt Carbon
= U * CVc * 100 / GCV of Coal
CVc – CV of Carbon 8077.8 kcal/kg
U = Carbon in ash / kg of coal
= Ash * C (Carbon in coal)
100 100 - C
05/08/19 39Manohar Tatwawadi

40. Influencing Factors - Unburnt Carbon Loss
• Type of mills and firing system
• Furnace size
• Coal FC/VM ratio, coal reactivity
• Burners design / condition
• PF fineness (Pulveriser problems)
• Insufficient excess air in combustion zone
• Air damper / register settings
• Burner balance / worn orifices
• Primary Air Flow / Pressure
05/08/19 40Manohar Tatwawadi

41. CO Loss (Controllable)
• Ideally, average CO at gooseneck after combustion
completion should be below 100 ppm and no single
value over 200 ppm
• CO monitors at ID fan discharge in all boilers to
supplement O2 feedback
C + O2 = CO2 + 8084 kcal / kg of Carbon
2C+ O2 = 2CO + 2430 kcal / kg of Carbon
2H2+ O2 = 2H2O + 28922 kcal / kg of Hydrogen
S + O2 = SO2 + 2224 kcal / kg of Sulphur
(We lose 5654 kcal for each kg of CO formed)
05/08/19 41Manohar Tatwawadi

42. Moisture Loss
Fuel Hydrogen Loss
This loss is due to combustion of H present in fuel. H is
burnt and converted in water, which gets evaporated.
Fuel Moisture Loss
This loss is due to evaporation and heating of inherent
and surface moisture present in fuel. (Can be reduced
by judicious sprays in coal yards)
05/08/19 42Manohar Tatwawadi

43. Computation - Moisture Loss
Total Moisture Loss
= (9H+M) * Sw / GCV of Coal
Sw – Sensible Heat of water vapour
= 1.88 (Tgo – 25) + 2442 + 4.2 (25 - Trai)
The moisture in flue gases (along with Sulphur in fuel) limits
the temperature to which the flue gases may be cooled due
to corrosion considerations in the cold end of air heater, gas
ducts etc.
05/08/19 43Manohar Tatwawadi

44. Other Losses
1. Sensible Heat Loss of ash
• Bottom Ash Hoppers
• Eco Hoppers
• AH Hoppers
• ESP hoppers
Sensible Heat Loss (%) = (X / GCV) *100 (~0.5-0.6 %)
X = [{Ash * Pflyash * C pash
* (T go
- T rai
)}
+ {Ash * Pahash * C pash
* (T go
- T rai
)}
+ {Ash * Peash * C pash
* (T gi
-T rai
)}
+ {Ash * Pba * C pash
* (T ba
- T rai
)}]
05/08/19 44Manohar Tatwawadi

45. Other Losses
2. Radiation Loss through Bottom Ash Hopper
• Coal Flow Rate 135 Tons/Hr
• GCV of Coal 3300 Kcal/Kg
• Eqv. Heat Flux thro’ Bottom opening 27090 Kcal/hr/m2
• Bottom opening area of S-Panel 15.85 m2
Radiation Loss through Bottom Ash Hopper =
[H BOTTOM
* A S-PANEL
*100 ] / [Coal Flow * GCV * 1000]
= 0.096 %
05/08/19 45Manohar Tatwawadi

46. Other Losses
3. Coal Mill Reject Loss
• Coal Flow 135 T/hr
• Coal Mill Rejects 200 kg/hr
• GCV of Coal 3300 kcal/Kg
• CV of Rejects 900 kcal/Kg
• Mill Outlet Temp Tmillout
90 C
• Reference Temperature Trai
30 C
• Specific Heat of Rejects CpREJECT
0.16 kcal/Kg/C
Loss due to Mill Rejects = X / (Coal Flow * GCV * 1000)
X = [Rejects * (CVREJECT
+ CpREJECT
(Tmillout
– Trai
))* 100 ]
= (0.0408 %)05/08/19 46Manohar Tatwawadi

47. Other Losses
4. Radiation Loss
Actual radiation and convection losses are difficult to
assess because of particular emissivity of various
surfaces.
05/08/19 47Manohar Tatwawadi

48. HEAT CREDIT
Heat Credit due to Coal Mill Power
= [MP * 859.86 * 100] / [Coal Flow * GCV * 1000]
Coal Flow Rate Coal FLOW
Tons/Hr
Total Coal Mill Power MP kWh
GCV of Coal Kcal/Kg
05/08/19 48Manohar Tatwawadi

49. Computations
1. The proximate analysis of coal is used to estimate the
as-fired percentages of carbon & hydrogen using ‘Parr
Formula’and nitrogen using ‘Gebhardt Formula’.
a) UltC = (1-0.01Z)*Cp + (5.0*FuelA) - (50.0*UltS)
Where Z = FuelTM*100 + 110*FuelA + 10*UltS
Qp = (100 * HHV) / (100 - Z)
Vp = 100*(100*FuelVM - 10*FuelA -
10*UltS)/(100-Z)
Cp = 0.0015782 * Qp - 0.2226 * Vp + 37.69
Say Fixed Carbon – 23.5, VM – 22.2, TM – 10.6, Ash 43.7 %,
S – 0.4 %; Ultimate C = 34.9%05/08/19 49Manohar Tatwawadi

50. b) UltH = (1-0.01Z)*Hp + (1.0*FuelA) - (1.5*UltS)
Where Z = FuelTM*100 + 110*FuelA + 10*UltS
Qp = (100 * HHV) / (100 - Z)
Vp = 100 * (100*FuelVM-10*FuelA -
10*UltS)/(100-Z)
Hp = 0.0001707 * Qp +0.0653 * Vp -2.92
Ultimate H = 2.7 %
c) UltN = 2.10 - 1.2*FuelVM = 1.8 %
d) UltOAct = 100 - UltCAct + UltHAct + UltNAct +
UltSAct + FuelAAct + FuelTMAct)
= 5.9 %
05/08/19 50Manohar Tatwawadi

51. Proximate to Ultimate Conversion
Formulae used for conversion of proximate analysis to
ultimate analysis add to the uncertainty of results.
For some coals, its recommended to use Seyler & Dulong
formula for estimation of C & H and modified Gebardht
formula for estimation of N from proximate analysis.
It’s suggested to get proximate & ultimate analysis of few
coal samples done to validate the formulae being used.
05/08/19 51Manohar Tatwawadi

52.
2) The flue gas O2 reading from zirconia probe is based
on a wet analysis. For comparison with the orsat or the
test grid readings, it must be converted to a dry analysis.
If the % moisture in the flue gas is unknown, a typical
value of 8% can be used.
O2 dry = O2 wet / (1-%Moisture/100)
Say O2
dry = 3.2 / (1 – 8 / 100) = 3.48 %
05/08/19 52Manohar Tatwawadi

53. Manual Inputs Units Symbol Value
Unit Load MW L 210
FW Flow at Eco Inlet T/hr Ffw 615
Wet Bulb Temp C Wb 24
Dry bulb Temp C Db 30
Barometric Pressure mmHgC BP 760
Total Coal Flow T/hr Fin 140
Unburnt C in Bottom Ash % Cba 1.2
Unburnt C in Flysash % Cfa 0.4
Radiation & Unaccounted Loss % Lrad 1.2
% of Flyash to Total Ash % Pfa 80
% of Bottom ash to Total Ash % Pba 20
Ultimate Analysis - As Fired
Carbon % Ca 36.4
Sulfur % S 0.6
Hydrogen % H 2.8
Moisture % M 12.2
Nitrogen % N 1
Oxygen % O 7
Ash % A 40
Gross Calorific Value kcal/kg Gcv 3320
05/08/19 53Manohar Tatwawadi

54. Avg. Flue Gas O2 - APH Out % O2out 5.0
Avg. Flue Gas CO2 - APH Out % CO2out 14.3
Avg. Flue Gas CO - APH Out ppm COout 50
Avg. Flue Gas Temp - APH In C Tgi 350
Avg. Flue Gas Temp - APH Out C Tgo 135
Primary Air to APH Temp In C Tpai 40
Primary Air from APH Temp Out C Tpao 325
Secondary Air to APH Temp In C Tsai 34
Secondary Air from APH Temp Out C Tsao 325
Total Secondary Air Flow T/hr Fsa 450
Total Primary Air Flow T/hr Fpa 250
Design Ambient / Ref Air Temp C Tref 30
05/08/19 54Manohar Tatwawadi

55. Computations
Losses - Test Conditions Unit Symbol Value
Dry Gas Loss
= Sh*100/(Gcv*4.186) % Ldg 4.617
Carbon in fuel % Ca 36.4
Sulfur in fuel % S 0.6
Carbon in ash / kg of fuel kg/kg coal U 0.00225
Specific heat of gas kg/kg/C Cp 30.6
Avg. Flue Gas Temp - APH Out C Tgo 135
Unburnt C in ash = Pfa/100*Cfa + Pba/100*Cba % Cash 0.56
C in ash / kg of coal = A/100*Cash/(100-Cash) kg U 0.00225
Total air flow = SA + PA flow T/hr Fta 700
Ratio SA flow to Total Air flow=Fsa/Fta % Rsa 0.64
Ratio PA flow to Total Air flow=Fpa/Fta % Rpa 0.36
Weighted Temp Air In = Tsai*Rsa + Tpai*Rpa C Trai 36.1
Weighted Temp Air Out = Tsao*Rsa + Tpao*Rpa C Tao 325
05/08/19 55Manohar Tatwawadi

56. Avg. Flue Gas CO2 - APH Out % CO2out 14.3
Gross CV kcal/kg Gcv 3315.2
Weight of dry gas = (Ca+S/2.67-
100*U)/(12*CO2out) kg/kg coal Wd 0.2121
Sensible Heat dry gas = Wd*30.6(Tgo-Trai) kJ/kg Sh 641.66
Loss due to Unburnt Carbon
= U*CVc*100/Gcv % Luc 0.55
Carbon in Ash / kg of coal kg/kg coal U 0.00225
CV of Carbon kcal/kg CVc 8077.8
Gross CV kcal/kg Gcv 3320
Loss due to moisture in fuel
= Sw*M/(Gcv*4.186) % Lmf 2.284
Moisture in Fuel % M 12.2
Avg. Flue Gas Temp - APH Out C Tgo 135
Weighted Temp Air - APH In C Tai 36.1
Gross CV kcal/kg Gcv 3320.0
Sensible heat of water vapour Sw = 1.88*(Tgo-
25)+2442+4.2*(25-Trai) kJ/kg Sw 2602
05/08/19 56Manohar Tatwawadi

57. Loss due to Hydrogen in Fuel
=9*H*Sw/(Gcv*4.186) % Lhf 4.72
Hydrogen in fuel % H 2.8
Loss due to Carbon monoxide
= COoutp*7*Cvco*(Ca-100*U) /3 /
(CO2out+Cooutp) / Gcv % Lco 0.021
Avg. Flue Gas CO2 - APH Out % CO2out 14.3
Avg. Flue Gas CO - APH Out % Cooutp 0.005
Carbon in fuel % Ca 36.4
CV of Carbon Monoxide kcal/kg CVco 2415
Gross CV kcal/kg Gcv 3320
Carbon in Ash / kg of coal kg/kg coal U 0.0023
05/08/19 57Manohar Tatwawadi

58. Loss due to moisture in air
= Ma*1.88*(Tgo-Trai)*100/(Gcv*4.186) % Lma 0.139
Carbon in fuel % Ca 36.4
Hydrogen in fuel % H 2.8
Sulfur in fuel % S 0.6
Oxygen in fuel % O 7
Carbon in ash / kg of fuel kg/kg coal U 0.0023
Gross CV kcal/kg Gcv 3320
Moisture in Air (from Psychrometric Chart) kg/kg Mwv 0.0165
Ref.air temp C Trai 36.14
Avg. Flue Gas Temp - APH Out C Tgo 135
Avg. Flue Gas O2 - APH Out % O2out 5
Avg. Flue Gas N2 - APH Out = 100 - (O2out-
CO2out-Cooutp) % N2out 80.7
Stoichiometric air = (2.66*(C-
U*100)+7.937*H+0.996*S-O)/23.2 kg/kg coal Sa 4.83
Excess Air = 1+[(O2out-Cooutp/2)]/[0.2682*N-
(O2out-Cooutp)] Ea 1.30
Total Moisture in air = Sa*Ea*Mwv % Ma 0.1036
05/08/19 58Manohar Tatwawadi

59. Gas Temp Leaving AH - Corr to design ambient
Ambient Temp - test C Tad 30
Ambient Temp - design C Tadd 30
Ref. Air Temp - test C Trai 36.14
Ref. Air Temp - design C Trad 36.14
=Tadd+(Trai-Tad)
Gas Temp entering AH - test C Tgi 350
Gas Temp leaving AH - test C Tgo 135
Gas Temp leaving AH (Corr) C Tgc 135.00
=(Trad*(Tgi-Tgo)+Tgi*(Tgo-Trai)) /
(Tgi-Trai)
05/08/19 59Manohar Tatwawadi

60. Loss due to moisture in air
= Mad*1.88*(Tgc-Trad)*100/(Gcvd*4.186) % Lmac 0.107
Carbon in fuel - design % Cd 37
Hydrogen in fuel - design % Hd 2.3
Sulfur in fuel - design % Sd 0.3
Oxygen in fuel - design % Od 7.6
Carbon in ash / kg of fuel kg/kg coal U 0.0023
Gross CV - design kcal/kg cvd 3300
Moisture in Air (from Psychrometric Chart) kg/kg Mwvd 0.013
Ref.air temp - design C Trad 36.143
Avg. Flue Gas Temp - APH Out (Corr) C Tgc 135.00
Avg. Flue Gas O2 - APH Out % O2out 5
Avg. Flue Gas N2 - APH Out = 100 - (O2out-CO2out-
Cooutp) % N2out 80.7
Stoichiometric air = (2.66*(Cd-
U*100)+7.937*Hd+0.996*Sd-Od)/23.2 kg/kg coal Sad 4.69
Excess Air = 1+[(O2out-Cooutp/2)]/[0.2682*N2out-
(O2out-Cooutp)] Ead 1.30
Total Moisture in air = Sad*Ead*Mwvd % Mad 0.0792
05/08/19 60Manohar Tatwawadi

61. THANKS
05/08/19 61Manohar Tatwawadi