Accuracy Improvement Analysis of the Standard Indirect ...3986 and standard DIN EN 12952-15 [1] are valid. If solid fuel is used, its mass flow is cal-culated indirectly according

Accurate Analysis of Boiler Efficiency

100 VGB PowerTech 12/2008

Accuracy Improvement Analysis of the Standard Indirect Method for Determining a Steam Boiler’s EfficiencyAndrej Senegacnik, Igor Kuštrin and Mihael Sekavcnik

Authors

Dr. Andrej Senegacnik, Assistant Professor

Dr. Igor Kuštrin, Teaching Assistant

Dr. Mihael Sekavcnik, Assistant Professor

University of Ljubljana Faculty of Mechanical Engineering Ljubljana/Slovenia.

Kurzfassung

Verbesserte Methoden zur Bestimmung des

Keselwirkungsgrades

Der Kesselwirkungsgrad von Kohlekraftwerken wird gewöhnlich nach standardisierten Verfah-ren bestimmt. Bei Einsatz eines Festbrenn-stoffs, wird der Massenstrom indirekt nach dem in DIN 12952-15 beschriebenen Verfah-ren berechnet. In dem vorliegenden Beitrag werden bestimmte Veränderungen an der standardisierten Methode DIN 12952-15 hin-sichtlich der Konsistenz von Berechnungen und die Genauigkeit der Ergebnisse mit der Sensitivitätsanalyse vorgeschlagen, präsentiert und bewertet,. Die wesentlichen Berechnungs-verfahren bleiben identisch mit DIN 12952-15. Es werden sechs Veränderungen berücksich-tigt. Vier davon beeinflussen die Bestimmung der entsprechenden Rauchgasmasse, näm-lich: nicht Vernachlässigung der partiellen Oxi-dation des Kohlenstoffes zu CO, nicht Ver-nachlässigung von Unverbranntem in der Asche und Schlacke bei der Bestimmung des Luftüberschusses mit zwei Modellen und nicht Vernachlässigung von Restwasser in der Rauchgasmessprobe. Die fünfte Veränderung behandelt den Einfluss der kalten Falschluft und die sechste Veränderung berücksichtigt die Verwendung der Berechnungsmethode der Enthalpie für Rauchgas und Verbrennungs-luft nach VDI 4670. Der Einfluss der vorge-schlagenen Veränderungen auf den Kesselwir-kungsgrad wurde mit zwei realen Datenreihen für Stein- und Braunkohle bewertet.

Introduction

The efficiency of coal-fired power plants is usually determined according to standardised procedures. Currently, the Guidelines VDI 3986 and standard DIN EN 12952-15 [1] are valid. If solid fuel is used, its mass flow is cal-culated indirectly according to the procedures stated in DIN 12952-15. The indirect method requires the determination of boiler losses. Losses can be measured directly except for radiation and convection losses which are es-timated according to the standard procedure stated in DIN 12952-15. The article at hand proposes, presents and evaluates some modi-fications of the standardised indirect method DIN 12952-15 regarding the consistency of computations and accuracy of the results. Most of the modifications were introduced re-cently in reference [2] where they were treated generally, i.e. from a stoichiometric calcula-tion point of view. Additional research pre-sented in this paper is focused on incorporat-ing additional calculations into the standard procedure [3] and to evaluate their impacts using sensitivity analysis. The main flow of computations remains identical to DIN 12952-15. Six modifications are considered. Four of them affect the referred flue gas mass deter-mination, i.e.: partial oxidation of carbon to CO, including unburned matter in ash and slag while determining the excess air ratio with two models and including residual water vapour content in the flue gas sample. The fifth modification studies the impact of cold uncontrolled leakage air. The sixth modifica-tion is applying the VDI 4670 procedure [4] for flue gas and combustion air enthalpies cal-culation. The impacts of modifications were studied for two real data sets – for hard coal and lignite.

Air Ratio Determination

Par t i a l Ox ida t ion o f Carbon t o CO ( I )

If some of the carbon from fuel burns to CO instead to CO2 the actual oxygen consump-tion is lower than the calculated consumption according to DIN 12952-15. To evaluate the

CO impact, the carbon from fuel should be divided into quantities of carbon combusted to CO2 and to CO, respectively.

Let the factor αCO2 be a quantity of carbon forming CO2. The factor αCO2 can be calculat-ed exactly with the next derivative formulae:

γCO2d1,8650 ∙––––––∙ γC – λVAod γCO2Ad γCOdαCO2 = ––––––––––––––––––––––––––––––––––––– (1)

γCO2dγC ∙1,8534 + 1,865 ∙––––––∙∙ γCOd

Factor αCO2 is dependent on λ, γCOd and γCO2d (if the γO2d is measured in the flue gas, the γCO2d value needs to be calculated with the formulae (6) and (7)).

Lambda – λ, is calculated from the basic pa-rameters which are given in DIN 12952-15 and are complemented with the carbon mon-oxide (CO) coefficients which are calculated according to [5]. The complemented equa-tions are:

µAod = 11,5122 αCO2 γC + 5,7561 (1 – αCO2) γC + 34,2974 γH + 4,3129 (2) γS – 4,3129 γO

µGod = 12,5122 αCO2 γC + 6,7561 (1 – αCO2) γC + 26,3604 γH + 5,3129 (3) γS – 3,3129 γO + γN

VGod = 8,8930 αCO2 γC + 5,3847 (1 – αCO2) γC + 20,9724 γH + 3,3190 (4) γS – 2,6424 γO + 0,7997 γN

µCO2 = 3,6699 αCO2 γC + 0,0029 (1 – αCO2) γC + 0,0173 γH + 0,0022 (γS – γO) (5)

If γCO2d is measured λ is calculated according to: VGod γCO2d – γCO2dλ = –––– ∙–––––––––––– ∙ +1 (6) VAod γCO2d – γCO2Ad

if yO2d is measured λ is calculated according to: VGod γO2dγ = –––– ∙––––––––––∙ +1 (7) VAod γO2Ad – γO2d

The upper formulae for λ are given in [5].

Iteration is needed since factors αCO2 and λ are correlated. The CO impact on referred flue-gas mass µG is always negative. This means that in presence of CO in flue gas, actual flue gas mass flow is lower than


VGB PowerTech 12/2008 101

flue gas mass flow calculated according to DIN 12952-15. F i g u r e 1 shows the impact of CO content in dry flue gas on referred flue gas mass µG. Actual operating points are also marked. The CO impact on µG is negative. If the CO content would rise to 1000 ppm, the difference of referred flue gas mass µG would be in the case of hard coal – 0.28 % and in the case of lignite – 0.22 %. The gradient of CO impact is slightly higher in the case of hard coal due to the larger mass fraction of carbon in coal.

Unbur ned Combus t ibl e s i n Ash and S lag

The air ratio is calculated on the basis of the measured flue gas composition at the boiler’s outlet and the fuel composition. Standard pro-cedure for the flue gas mass flow calculation assumes that all the carbon from the “burned” fuel is burned completely and that the compo-sition of the “burned” fuel matches the com-position of the supplied fuel i.e. fuel sample. In practice, some of the larger coal dust parti-cles do not burn completely; they leave the boiler with ash as coke. Therefore, the un-burned carbon does not participate in CO2 formation. Actual oxygen consumption is therefore lower. In order to determine the ex-cess air ratio more accurately, unburned car-bon should be subtracted from the carbon mass fraction in the fuel and added to the ash mass fraction. The air ratio calculation should then be repeated using the new “apparent fuel composition”. Two explanatory models are in-troduced in the following sections.

In the following paragraphs annotations “coalX” means composition of the fuel sam-ple while “γX” means apparent fuel composi-tion (i.e. composition that actually burned).

Model 1 – Unburned Combustible Matter in Ash and Slag is Pure Carbon (II)

Model 1: The assumption is that the combus-tible matter in ash and slag is pure carbon. New “apparent” fuel composition, which ac-tually burns, is therefore:

γC = coalC – lu (1 – coalAsh – coalH2O) (8)

γH = coalH (9)

γS = coalS (10)

γO = coalO (11)

γN = coalN (12)

γAsh = coalAsh + lu (1 – coalAsh – coalH2O) (13)

γH2O = coalH2O (14)

Model 2 – Composition of Unburned Combustible Matter in Ash and Slag Matches the Combustible Component of Fuel – Linear Model (III)

Model 2: The assumption is that the combus-tible matter in ash and slag has the same com-

position as the combustible component of the fuel. New “apparent” fuel composition is therefore:

γC = (1 – lu) coalC (15)

γH = (1 – lu) coalH (16)

γS = (1 – lu) coalS (17)

γO = (1 – lu) coalO (18)

γN = (1 – lu) coalN (19)

γAsh = coalAsh + lu (coalC + coalH + coalS + coalO + coalN) (20)

Sensitivity Analysis

F i g u r e 2 shows the impact of unburned combustibles in ash and slag to referred flue gas mass µG. The x-axis of Figure 2 represents the amount of unburned combustible in ash because there were no unburned combustibles in slag. To get a more objective impression about the impact of unburned combustibles in ash and slag, the total amount of unburned combustible can be also expressed as a mass fraction of carbon in the supplied fuel [6]. In-dex unburned carbon is calculated by expres-sion (21).unburned carbon

mSL µSL + mFA µFA= 100 ∙–––––––––––––––∙ % (21) mFo γC

The impact of unburned combustibles in ash and slag on referred flue gas mass µG is al-ways negative. This means that in a presence of unburned combustibles in ash and slag, ac-tual flue gas mass flow is always lower than flue gas mass flow calculated according to DIN 12952-15.

The results of Model 1 and Model 2 are pre-sented in Figure 2. The proposed models are

extreme cases. The actual impact lies some-where in between. From the results we can conclude that the average impact gradient of unburned combustibles to referred flue gas mass is

hard coal: – ≈ – 0.87 % of referred flue-gas mass per 1 % of unburned carbon

lignite: – ≈ – 0.71 % of referred flue-gas mass per 1 % of unburned carbon

The impact is larger for hard coal due to a higher mass fraction of carbon in the fuel. In the case of lignite, when the ratio γC/γH is lower, the gap between “pure carbon” and the “linear model” becomes wider.

Res idua l Vapour Con ten t i n Gas Sample ( IV)

The standard procedure for the flue gas mass flow calculation requires a dry flue gas sam-ple. The gas sample is usually dried by cool-ing to about 4 °C. Therefore, volume content of water vapour in the flue gas leaving the cooler is about 0.8 %. This means that the measured volume contents of the other flue gas components are lower than they would be if the flue gas sample was completely dry. To establish volume contents in completely dry flue gas sample the following correction should be applied:

saturation pressureof water at 4 °CυSat = –––––––––––––––––––––––– (22)

flue gas pressure in the cooler

γ*CO2d γCO2d = ––––––––– (23) 1 – υSat

γ*O2d γO2d = ––––––––– (24) 1 – υSat

γ*COd γCOd = ––––––––– (25) 1 – υSat

DIN 12952-15

Actual operatingpoint

Hard coal

Lignite

Rel

ativ

e ch

ange

of r

efer

red

flue

gas

mas

sw

hen

CO

is c

onsi

der

ed, %

-0.30

-0.25

-0.20

-0.15

-0.10

-0.05

0.00

0 0.0002 0.0004 0.0006 0.0008 0.001 0.0012

CO content in dry flue gas

Figure 1. Impact of CO content on referred flue gas mass µG.



where asterisk annotates measured volume contents of flue gas components in flue gas containing residual vapour. The annotations without an asterisk are used for volume con-tents of flue gas components in completely dry flue gas.

Sensitivity Analysis

The Bunte triangle in this point is used for ex-planatory purposes only because the triangle is valid only for completely dry gases. From the formulae (22) to (25) it is evident that dur-ing the correction procedure, values of γCO2d or γO2d are increased by an equal percentage. Therefore, the absolute variation ∆γCO2d or ∆γO2d, formulae (26)

∆γO2d = γO2d – γ*O2d or

∆γCO2d = γCO2d – γ*CO2d (26)

is thus proportional to the value of γCO2d or γO2d. Usually in flue gas resulting from coal combustion the value γCO2d is 4 to 5 times larger than γO2d. Therefore, the absolute vari-ation ∆γCO2d is also four to five times larger than ∆γO2d.

From the Bunte triangle, F i g u r e 3 , which graphically shows the relations between CO2, O2 content in flue gas and λ, it is obvious that we should distinguish between two cases with opposite effects:

a) oxygen content yO2d is used to calculate the referred flue gas mass µG,

b) carbon dioxide content yCO2d is used to cal-culate the referred flue gas mass µG.

Figure 3, Detail B, explains this graphically. Origin point C moves to D in the case when CO2 is considered/measured (case b). If O2 is considered/measured the origin point C moves to point E (case a) and the impact is positive.

This means that if the residual water vapour in the flue gas sample is not neglected the actual flue gas mass flow is greater than flue gas mass flow calculated according to DIN 12952-15. In case b, when CO2 is considered/meas-ured the impact changes sign and magnitude. For example the magnitude in hard coal case b is ≈ –2.6 times larger than in hard coal case a, F i g u r e 4 .

F i g u r e 5 shows the sensitivity of the excess air ratio which is evaluated with partial deriv-atives (27). It shows how quickly the excess air ratio is changing if the content of CO2 or O2 are changing.

− (γ – 1) VGod (γCO2Ad – γCO2d)––––––– = –––––––––––––––––––− (γCO2d) VAod (γCO2d – γCO2Ad)2

or (27)

− (λ – 1) VGod γO2Ad––––––– = ––––– –––––––––––− (γO2d) VAod (γO2Ad – γO2d)2

Sensitivity of the excess air is weakly depend-ent on the fuel composition and therefore on Figure 5 only the results for lignite are pre-sented. Essentially the absolute impact of both gases O2 and CO2 is quite similar and that the sensitivity is increasing when air ratio is in-creasing. From Figure 3 it can also be con-cluded that in case a the impact of residual water vapour in the flue gas sample decreases when the yO2d approaches zero. In case b, the impact of residual water vapour in the flue gas sample maximises when γCO2d approaches the stoichiometric referred CO2 volume. In this limiting case the ratio between the CO2 and O2 impact limits to (– ∞).

Combustion Air Heat Input (V)

Standard procedure assumes that combustion air enters the boiler in a controlled manner through air heaters. Of course some of the combustion air enters the boiler elsewhere (leakage air) usually having a lower tempera-ture than the controlled air. Usually controlled air temperature used in air-heat-input calcula-tions is measured at the boiler’s envelope after the forced draft fan.

The standard [1] includes a correction formu-la but it should be stated more clearly that at least a rough energy balance of the air heater should be made to estimate the quantity of leakage air.

From the provided data, for a hard coal-fired power plant, a simple energy and mass bal-ance for the air heater was established. The result shows that there is about 13.5 % of leakage air. To evaluate the impact of air leakage, the following assumptions were used:

the mass content of leakage air is –xLA = 0.135

the temperature of leakage air is 15 to 30 °C –lower than controlled-air temperature.

DIN 12952-15

Actual operatingpoint, unburnedcarbon 0.52 %

Linear model

Pure carbon model

Rel

ativ

e ch

ange

of r

efer

red

flue

gas

mas

s, %

-2.5

-2.0

-1.5

-1.0

-0.5

0.0

0.00 0.02 0.04 0.06 0.08 0.10 0.12

Unburned matter in ash

Unburned carbon1.73 %

Hard coal

Figure 2. Impact of unburned combustibles in ash and slag, hard coal.

Detail B Detail B

21

^yCO2

CO2

CO2 + O2210

yCO2d

yO2d

A

1 / l

∆yCO2d

yCO2d

yO2d

∆yO2d

E

D

C

Figure 3. Bunte triangle.



Sens i t iv i ty ana lys i s

Leakage combustion air has an impact just on the heat input proportional to the fuel burned Q(N)ZF. Therefore, there is no impact on the referred flue gas mass µG.

Different amounts of delivered heat to the boiler at the same useful heat output QN ,

means also different boiler efficiency and consequently also different mass flow of burned fuel. F i g u r e 6 presents the impact of leakage air on the flue gas mass flow mG, leaving the air heater. In Figure 6 several tem-perature differences between controlled and leakage air are introduced. The impact of not neglecting the cold air leakage is positive, i.e. the flue gas mass flow leaving the air heater is increased.

Air and Flue Gas Enthalpy Calculation (VI)

DIN 12952-15 calculates the specific heat of flue gas and combustion air using polynomial equations. This calculation procedure takes into account just air, water vapour and CO2 content. More accurate calculation procedures take into account all flue gas components, i.e. N2, O2, Ar, Ne, H2O, CO2, CO and SO2 as given in VDI-Richtlinien, VDI 4670 – “Ther-modynamische Stoffwerte von feuchter Luft und Verbrennungsgasen” [4].

For the VDI 4670 calculation of mass frac-tions of flue gas and the combustion air of the components (N2, O2, Ar, Ne, H2O, CO2, CO, SO2) should be known. All the neces-sary formulae for the determination of re-ferred masses µi (kg/(kg of fuel)) were taken from Brandt [5].

µAD = λ µAod (28)

µCO2 = µCO2o + (λ – 1) µAod ϰCO2Ad (29)

µO2 = (λ – 1) µAod ϰO2Ad (30)

µN2 = γN + λ µAod ϰN2Ad (31)

µAr = λ µAod ϰArAd (32)

µCO = 2,3321 (1 – αCO2) γC (33)

µSO2 = 1,9981 γS (34)

µH2O = µH2OF + µAod λ ϰH2OAd (33)

Sens i t iv i ty Ana lys i s

The application of the more accurate proce-dure VDI 4670 only affects the amount of en-

ergy of the flue gas leaving the boiler – the flue gas loss lG. F i g u r e 7 presents the im-pact of VDI 4670 as used on the boiler’s flue gas loss. It is evident that the VDI 4670 en-thalpy calculation lowers flue gas loss. In the lignite case, the influence is almost twice as large as for hard coal. The reason for this is the water vapour content in the flue gas. The water content amounts 4.5 % for hard coal and 14.0 % for lignite. The overall impact of VDI 4670 as used in DIN 12952-15 is there-fore dependent on the flue gas composition or fuel composition.

Data

Some major input data used in the computa-tions are summarised in Ta b l e 1 .

Results

F i g u r e 8 graphically represents the main results of this research – the absolute change of boiler efficiency for particular modifica-tion and all for modifications simultaneously. The data from Table 1 were used in the calcu-lation.

Modification I – – partial oxidation of car-bon to CO: the change is small due to a very low CO content in the flue gas.

Modifications II and III – – composition of unburned combustibles in ash and slag: as expected, these two modifications have im-portant effects. The effect is proportional to the content of the unburned combusti-bles in ash and slag. Unburned combusti-bles affect the computed referred flue gas mass due to the application of the apparent

DIN 12952-15

Hard coal

Rel

ativ

e ch

ange

of r

efer

red

flue

gas

mas

s, %

Temperature of flue gas sample, ˚C

O2 consideration

CO2 consideration

0.6

0.4

0.2

0.0

-0.2

-0.4

-0.6

-0.8

-1.0

-1.21 2 3 4 5 6 7 8 9 100

Figure 4. Impact of residual vapour content in gas sample, hard coal.

Sen

sitiv

ity o

f exc

ess

air

ratio

(l-1

)

Air ratio, l

10

20

5

15

25

0

-10

-20

-5

-15

-251 1.2 1.4 1.6 1.8 2

CO2

O2

Lignite

Figure 5. Sensitivity of excess air ratio, lignite.



Table 1. Major input data.

Input Data Units Hard coal Lignite

O2 content in flue gas (by volume, dry), AH outlet

- 0.058 0.030

CO content in flue gas (by volume, dry), AH outlet

- 3.274E-05 9.500E-05

Flue gas temperature, AH outlet °C 137.1 168.7

Air temperature, AH inlet °C 55.5 51.91

Calorific value of coal kJ/kg 23,150 10,597

Carbon content, fuel (by mass) - 0.5978 0.2906

Hydrogen content, fuel (by mass) - 0.0361 0.0259

Sulphur content, fuel (by mass) - 0.0074 0.0169

Oxygen content, fuel (by mass) - 0.0511 0.0621

Nitrogen content, fuel (by mass) - 0.0124 0.0027

Ash content, fuel (by mass) - 0.1603 0.0780

Water content, fuel (by mass) - 0.1349 0.5238

Ash collection efficiency - 0.390 0.053

Unburned combustibles content (by mass), slag

- 0.0000 0.0027

Unburned combustibles content (by mass), ash

- 0.0323 0.0010

Calorific value of unburned combustibles, slag

kJ/kg 33,000 27,200

Calorific value of unburned combustibles, ash

kJ/kg 33,000 27,200

Slag temperature °C 1500 330

Volatile matter content, ash - 0.05 0.05

fuel composition instead of the actual fuel composition. Losses directly connected to the referred flue gas mass are therefore af-fected. Modifications II and III cannot be applied simultaneously. The difference in results of modifications II and III is not significant.

Modification IV – – residual water vapour in the flue gas sample: magnitude and di-rection of change depends on which gas is considered in the calculation and the flue-gas sample temperature (4 °C is used in Figure 8). Due to opposite impacts, both results for CO2 and O2 can be introduced

simultaneously. It is evident that the impact of CO2 is the largest and most important factor.

Modification V – – combustion-air heat in-put: in cases when the amount of leakage air is less than 20 %, the flue gas loss in-creases up to 0.01 %.

Modification VI – – VDI 4670 guidelines application: flue gas loss is lower up to 0.02 %. The water vapour content in the flue gas dictates the deviation magnitude.

All modifications simultaneously: – From Figure 8 it is clear that the particular modi-fications cause deviations in both directions – positive and negative. Therefore, they compensate for each other to some degree. The final overall deviation is somehow pro-portional to the “total sum” of the particular deviations. The final overall deviation of the boiler efficiency is positive.

It can be seen from Figure 8 that just the in-clusion of leakage air always lowers the boiler efficiency. Residual water vapour in the flue gas sample can lower or raise efficiency, de-pending on whether CO2 or O2 is used in the boiler efficiency calculation. If O2 is use, we get the overall results shown in column ALL 1, Figure 8. If CO2 is used we get dra-matically different results as shown in column ALL 2.

For these two studied examples with hard coal and lignite, with particular input data from Table 1, the overall absolute change in boiler efficiency due to the proposed modifications is relatively small. In this particular case when the oxygen content is used for boiler efficien-cy determination, the overall change of effi-ciency is +0.009 % for hard coal, and +0.002 % for lignite (Figure 8). If the carbon dioxide content is used, the overall change of eff iciency is +0.07 % for hard coal and +0.06 % for lignite.

It can be concluded from Figure 8 that the proposed modifications, which provide more accurate calculations, increase the calculated value of boiler efficiency in almost all cases. This means that the actual (more accurate) boiler efficiency is higher than the value of efficiency given according to DIN 12952-15. In some extreme cases with very cold air leak-age, high O2 value with high residual water vapour with low unburned carbon etc. can lead to the opposite situation.

Conclusion

The article at hand presents and evaluates some modifications of the standardised indi-rect method for steam boiler efficiency deter-mination, DIN 12952-15. The proposed modi-fications improve consistency of computa-tions and accuracy of results. Six modifica-

DIN 12952-15

Rel

ativ

e ch

ange

of f

lue

- ga

s m

ass

flow

leav

ing

air

heat

er, %

Ratio of preheated air in air heater

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.60 0.65 0.70 0.75 0.80 0.85 0.90 0.95 1.00

15 ˚C

20 ˚C

25 ˚C

30 ˚C

Temperature differencebetween controlled air

and leekage air

Hard coal

Actual amount ofcontrolled air = 0.865

Figure 6. Impact of air leakage on computed flue gas mass flow, hard coal.



tions are studied. Four of them relate to more accurate air ratios, flue gas mass determina-tion including partial oxidation of carbon to CO; two models including unburned combus-tibles in ash and slag; the fourth including the residual water vapour content in the flue gas sample. The fifth modification is to include the heat input of leakage air and the sixth is applying the VDI 4670 procedure in the en-thalpy calculation of flue gas and combustion air.

Sensitivity analysis was made for all six mod-ifications. The impact of the proposed modi-fications to the boiler efficiency was evaluat-ed on two real data sets for hard coal and lig-nite. It is demonstrated that the impacts of unburned combustibles in ash and slag and the impact of residual water vapour in the flue gas sample are the most influential factors in

accurate boiler efficiency determinations re-garding the above stated modifications. The impact sign and magnitude in the case of re-sidual water vapour in the flue gas sample de-pends on which gas is considered in calcula-tions, CO2 or O2 and the flue-gas sample tem-perature in the cooler. It is evident that the impact of CO2 has the greatest effect.

In two studied cases for hard coal and lignite, the proposed modifications increase the calcu-lated boiler eff iciency. If O2 is used in the calculation, the average deviation is ∆hB < +0.01 %; if CO2 is used, the deviations in-crease to ∆hB ≈ +0.07 %. Deviations of boiler efficiency are small due to low CO content and low content of unburned matter in ash and slag. If the amount of unburned carbon from fuel would be 1 %, the deviation of boiler efficiency would be higher than +0.1 %.

The analysis shows that boiler efficiency is decreased only by including leakage air and residual water vapour in the flue-gas sample if O2 is used in the λ calculation. All other mod-ifications increase the boiler efficiency com-pared to the standard procedure. The overall impact of all modifications is expected to be positive. This means that the actual boiler ef-ficiency is higher than the efficiency calcu-lated according to DIN 12952-15. The actual flue gas mass flow leaving the air heater is also lower up to 2 %.

Acknowledgment

The authors of the article at hand would like to thank VGB-FORSCHUNGSSTIFTUNG for supporting this research.

References

[1] DIN 12952-15, Wasserrohrkessel und Anlagen-komponenten – Tiel 15: Abnahmeversuche; Deutsche Fassung EN 12952-15:2003, Januar 2004.

[2] Sekavcnik, A., Kuštrin, I., and Oman, J.: Five Enhancements to the Standard Indirect Method for Determining a Steam Boiler’s Efficiency, VGB PowerTech, vol. 86, no. 3, 2006, pp. 82-86.

[3] Senegacnik, A., Kuštrin, I., Sekavcnik, M., and Oman J.: Analysis and Validation of Theoreti-cal Optimisation Potentials of Steam Boiler Ef-ficiency Determination by Use of Real Meas-uring Data – VGB FORSCHUNGSSTIFTUNG research project, Faculty of Mechanical Engi-neering, Ljubljana, 2008.

[4] VDI 4670 Thermodynamische Stoffwerte von feuchter Luft und Verbrennungsgasen, VDI Richtlinien, Oktober 2000.

[5] Brandt, F.: Brennstoffe und Verbrennungsrech-nung, 3. Auflage, Vulkan-Verlag GmbH, Essen, 1999.

[6] Kuštrin I., Oman J., and Senegacnik, A.: The collection of technical reports on tests of steam boilers’ of Slovenia, Faculty of Mechanical Engineering, Ljubljana, 1993-2008.

List of Symbols

Nomenclature and meanings of symbols matches the nomenclature in DIN 12952-15

Symbol Unit Description

α kg/kg Share of carbon forming CO2

coal kg/kg Fuel content – fuel sample (by mass)

lu – Ratio of unburned combusti-bles to supplied fuel mass flow

m kg/s Mass flow

Q kW Heat flow

V m3/kg Combustion air and flue gas volume (per unit mass of fuel)

Rel

ativ

e ch

ange

of t

he fl

ue g

as lo

ss, %

Lignite

Hard coal

DIN 12952-150.00

-0.02

-0.04

-0.06

-0.08

-0.10

-0.12

-1.14

-1.16

-1.18

-0.20

Figure 7. Impact of VDI 4670 enthalpy calculation in flue gas loss computation.

DIN 12952-15

Ab

solu

te c

hang

e of

boi

ler

effic

ienc

y, %

Hard coalLignite

-0.020

-0.010

0.000

0.010

0.020

0.030

0.040

0.050

0.060

0.070

0.080

CO2

O2

Ipartial oxida.of C to CO

II unburned combustibies in fuel pure carbon linear model

III IVresidual water

in fl. gas sample

Vuncontrolledcold air leak.

VIVDI 4670applied

ALL 1 ALL 2all cases

simultaneously

O2consi-

deration

O2consi-

deration

Figure 8. Absolute change of boiler efficiency.



υ m3/m3 Specific volume

ϰ kg/kg Flue gas/combustion air com-ponents by mass

ϰAd kg/kg Combustion air content by mass

γ m3/m3 Content by volume

∆ – Difference

µ kg/kg Combustion air/flue gas mass to fuel mass ratio

λ – Air ratio

γ kg/kg Fuel content – actual burned (by mass)

Subscripts and superscripts

* Measured value

^ Maximum

A Air

Ar Argon

Ash Ash

C Carbon

CO Carbon monoxide

CO2 Carbon dioxide

d Dry (basis)

F Fuel, burned fuel

FA Flue dust (dry ash)

Fo Fuel supplied

G Flue gas (combustion gas)H HydrogenH2O WaterLA Leakage (infiltrated) air / tramp airN, N2 NitrogenN Useful, effectiveNe Neono StoichiometricO, O2 OxygenS SulfurSat SaturationSL SlagSO2 Sulfur dioxideZ Heat input h

Documents

Accuracy Improvement Analysis of the Standard Indirect ...3986 and standard DIN EN 12952-15 [1] are valid. If solid fuel is used, its mass flow is cal-culated indirectly according