Chapter 4
Prepared by : Dr. N. Ait Messaoudene
Based on:
El-Wakil, Power Plant Technology, McGraw-Hill, 1984.
2nd semester 2012-2013
4.1 Introduction
Any material that can be burned to release thermal energy is called a fuel. Most familiar fuels consist primarily
of hydrogen and carbon. They are called hydrocarbon fuels and are denoted by the general formula CnHm.
Hydrocarbon fuels exist in all phases, some examples being coal, gasoline, and natural gas. Most liquid
hydrocarbon fuels are a mixture of numerous hydrocarbons and are obtained from crude oil by distillation. For
the sake of simplification, they are usually considered to be a single hydrocarbon for convenience. For example,
gasoline is treated as octane, C8H18, and the diesel fuel as dodecane, C12H26. Another common liquid
hydrocarbon fuel is methyl alcohol, CH3OH, which is also called methanol and is used in some gasoline
blends.
The gaseous hydrocarbon fuel natural gas, which is a mixture of methane and smaller amounts of other gases, is
often treated as methane, CH4, for simplicity. Liquefied petroleum gas (LPG) is a byproduct of natural gas
processing or the crude oil refining. It consists mainly of propane and thus LPG is usually referred to as
propane. However, it also contains varying amounts of butane, propylene, and butylenes.
Fossil fuels originate from the earth as a result of the slow decomposition and chemical conversion of organic
material. New combustible-fuel options include synthetic fuels (synfuels), which are liquids and gases derived
largely from coal, oil shale and tar sands.
Combustion is the conversion of a substance called a fuel into chemical compounds known as products of
combustion by combination with an oxidizer. The combustion process is an exothermic chemical reaction, i.e., a
reaction that releases energy as it occurs. Thus combustion may be represented symbolically by:
Fuel + Oxidizer = Products of combustion + Energy
Heats of reaction may be measured in a calorimeter, a device in which chemical energy release is determined by
transferring the released heat to a surrounding fluid. The amount of heat transferred to the fluid in returning the
products of combustion to their initial temperature yields the heat of reaction.
4.2 Coal
Coal is an abundant solid fuel found in many locations around the world in a variety of forms. The American
Society for Testing Materials, ASTM, has established a ranking system that classifies coals as anthracite (I),
bituminous (II), sub-bituminous (III), and lignite (IV), according to their physical characteristics.
As a solid fuel, coal may be burned in a number of ways. Starting with the smallest of installations, coal may be
burned in a furnace, in chunk form on a stationary or moving grate. Air is usually supplied from below with
combustion gases passing upward and ash falling through a stationary grate or dropping off the end of a moving
grate into an ash pit. A wide variety of solid fuels can be burned in this way.
In large installations, coal is crushed to a particular size, and sometimes pulverized to powder immediately
before firing, to provide greater surface exposure to the oxidizer and to ensure rapid removal of combustion
gases. Because of the wide variation in the characteristics of coals, specialized types of combustion systems
tailored to a specific coal or range of coal characteristics are used.
4.2 Liquid Fuels:
Liquid fuels are primarily derived from crude oil through cracking and fractional distillation. Cracking is a
process by which long-chain hydrocarbons are broken up into smaller molecules. Fractional distillation
separates high-boiling-point hydrocarbons from those with lower boiling points. Liquid fuels satisfy a wide
range of combustion requirements and are particularly attractive for transportation applications because of their
compactness and fluidity. Table “4.1” gives representative analyses of some of these liquid fuels. Compositions
of liquid and solid fuels, unlike gaseous fuels, are usually stated as mass fractions.
Table 4.1 Analysis of several liquid fuels
They are usually a mixture of hydrocarbons represented by CnHm, where m is a function of n depending on the
type of hydrocarbon. Table 4.2 gives a listing of the types of hydrocarbons found in crude and refined oils:
The fuel most suitable for utility powerplants is fuel oil. It comes in various grades, from light to heavy:
Table 4.5 gives a summary of some physical characteristics of fuel oils (ASTM Standard D 396).
4.3 Natural Gas
Natural gas is a mixture of hydrocarbons and nitrogen, with other gases appearing in small quantities. Table
“3.4” below shows the composition of samples of natural gases found in several regions of the United States.
For these samples, it is seen that the gases contain 83-94% methane (CH4), 0-16% ethane (C2H6), 0.5-8.4%
nitrogen and small quantities of other components, by volume. The ultimate analysis shows that the gases
contain about 65-75% carbon, 20-24% hydrogen, 0.75-13% nitrogen, and small amounts of oxygen and sulfur
in some cases. The higher heating values are in the neighborhood of 1000 Btu/ft3 on a volume basis and 22,000
Btu/lbm on a mass basis. In regions where it is abundant, natural gas is frequently the fuel of choice because of
its low sulfur and ash content and ease of use.
4.4 Liquid, gas, and solid by-products
These are Solid, liquid, or gaseous by-products resulting from human biological processes, manufacturing,
materials processing, consumption of goods, or any other human activity. Industrial wastes have received
increased attention as steam generator fuels for the double purpose of disposing of them and reducing the use of
oil.
Gaseous by-products are more attractive, with refinery gas the most suitable in the case of oil producing
countries like Saudi Arabia. Refinery gas is generated in the conversion of crude oil to gasoline and other
refinery products. It has a high heating value and is often blended with lower heating value gas by-products
prior to combustion.
4.5 Synthetic fuels
Also called synfuels, these are gaseous and liquid fuels produced largely from coal but also from various wastes
and biomass or natural gas.
An example is GTL or Gas to Liquid fuel:
4.6 Biomass
It is the generic name given to organic matter produced by plants (natural or from human grown crops), both
terrestrial and aquatic and their derivatives; it also includes animal manure. It can be considered as renewable
energy because of the rather short life cycle. It can also be considered a form of solar energy as plants use
photosynthesis for growth. Because of the high water content, it is not economical to transport them over large
distances and conversion must take place close to the source. However, biomass can be converted to liquid
(alcohol or oil) or gaseous (methane) fuels with higher energy density, making feasible transportation over long
distances.
4.7 Heat of Combustion
A chemical reaction during which a fuel is oxidized and a large quantity of energy is released is called
combustion. The oxidizer most often used in combustion processes is air. Pure oxygen O2 is used as an
oxidizer only in some specialized applications.
On a mole or a volume basis, dry air is composed of 20.9 percent oxygen, 78.1 percent nitrogen, 0.9 percent
argon, and small amounts of carbon dioxide, helium, neon, and hydrogen. In the analysis of combustion
processes, the argon in the air is treated as nitrogen, and the gases that exist in trace amounts are disregarded.
Then dry air can be approximated as 21 percent oxygen and 79 percent nitrogen by mole numbers. Therefore,
we consider that 1 mole of oxygen added to 0.79/0.21 = 3.76 mol of nitrogen form air,
During combustion, nitrogen behaves as an inert gas (it actually forms very small amount of nitric oxides called
NOx at very high temperatures). However, its presence greatly affects the outcome of a combustion process
since nitrogen usually enters a combustion chamber in large quantities at low temperatures and exits at
considerably higher temperatures, absorbing a large proportion of the chemical energy released during
combustion.
For most combustion processes, the moisture in the air and the H2O that forms during combustion can also be
treated as an inert gas, like nitrogen. When the combustion gases are cooled below the dew-point temperature of
the water vapor, some moisture condenses. It is important to be able to predict the dew-point temperature since
the water droplets often combine with the sulfur dioxide that may be present in the combustion gases, forming
sulfuric acid, which is highly corrosive. During a combustion process, the components that exist before the
reaction are called reactants and the components that exist after the reaction are called products:
For example:
C + O2
CO2
The fuel must be brought above its ignition temperature to start the combustion. The minimum ignition
temperatures of various substances in atmospheric air are approximately 260°C for gasoline, 400°C for carbon,
580°C for hydrogen, 610°C for carbon monoxide, and 630°C for methane. Moreover, the proportions of the fuel
and air must be in the proper range for combustion to begin. For example, natural gas does not burn in air in
concentrations less than 5 percent or greater than about 15 percent. These are called flammability limits.
Stoichiometr y and A-Fuel Ratio:
As you may recall from your chemistry courses, chemical equations are balanced on the basis of the
conservation of mass principle (or the mass balance), which can be stated as follows: The total mass of each
element is conserved during a chemical reaction. Or: the total number of atoms of each element is conserved
during a chemical reaction. Note that the total number of moles is not necessarily conserved during a chemical
reaction.
A frequently used quantity in the analysis of combustion processes to quantify the amounts of fuel and air is the
air–fuel ratio AF. It is usually expressed on a mass basis and is defined as the ratio of the mass of air to the mass
of fuel for a combustion process:
The mass m of a substance is related to the number of moles N through the relation m = NM, where M is the
molar mass.
The air–fuel ratio can also be expressed on a mole basis as the ratio of the mole numbers of air to the mole
numbers of fuel. But we will use the former definition. The reciprocal of air–fuel ratio is called the fuel–air
ratio.
Example from: Yunus A. Cengel and Michael A. Boles “Thermodynamics: An Engineering Approach”; 6th
Edition, McGraw Hill, 2007.
A combustion process is complete if all the combustible components of a fuel are burned to completion (with
the possibility of having excess oxygen in the products): all the carbon in the fuel burns to CO2, all the
hydrogen burns to H2O, and all the sulfur (if any) burns to SO2:
Conversely, the combustion process is incomplete if the combustion products contain any unburned fuel or
components such as C, H2, CO, or OH. Insufficient oxygen and insufficient mixing are some of the most
common causes of incomplete combustion. Another cause of incomplete combustion is dissociation, which
becomes important at high temperatures (formation of CO, C particles or soot, NOx… in the products).
The minimum amount of air needed for the complete combustion of a fuel is called the stoichiometric or
theoretical air. It is also referred to as the chemically correct amount of air, or 100 percent theoretical air. A
combustion process with less than the theoretical air is bound to be incomplete. The ideal combustion process
during which a fuel is burned completely with theoretical air (and no O2 is present in the products) is called the
stoichiometric or theoretical combustion of that fuel. For example, the theoretical combustion of methane is
The amount of air in excess of the stoichiometric amount is called excess air. It is usually expressed in terms of
the stoichiometric air as percent excess air or percent theoretical air; the reactants mixture is said to be fuel lean
in this case or a lean mixture. Amounts of air less than the stoichiometric amount are called deficiency of air
and are often expressed as percent deficiency of air; the reactants mixture is said to be a rich mixture in this
case. The amount of air used in combustion processes is also expressed in terms of the equivalence ratio, which
is the ratio of the actual fuel–air ratio to the stoichiometric fuel–air ratio.
For example, 50 percent excess air is equivalent to 150 percent theoretical air or an equivalence ratio of 66.67%
(lean mixture); and 10 percent deficiency of air is equivalent to 90 percent theoretical air or an equivalence ratio
of 111,11% (rich mixture).
Predicting the composition of the products is relatively easy (by performing a mass balance) when the
combustion process is assumed to be complete and the exact amounts of the fuel and air used are known.
However, actual combustion processes are hardly ever complete and it is impossible to predict the composition
of the products on the basis of the mass balance alone. Then the only alternative we have is to measure the
amount of each component in the products directly (perform a chemical analysis). A commonly used device to
analyze the composition of combustion gases is the Orsat gas analyzer (a device that determines the
composition through volume measurements).
Example from: Yunus A. Cengel and Michael A. Boles “Thermodynamics: An Engineering Approach”; 6th
Edition, McGraw Hill, 2007.
Example 4.3
Determine the molecular weight and stoichiometric mole and mass air-fuel ratios for the
Oklahoma gas mole composition given in Table 3.4.
Solution
Chemical Reaction Equation :
CH4 + 2O2 + 2(3.76)N2 → CO2 + 2H2O + 2(3.76)N2
The equation shows that there are 2 + 2(3.76) = 9.52 moles of air required for complete combustion of each
mole of methane. Similarly for ethane, the stoichiometric reaction equation is:
C2H6 + 3.5O2 + (3.5)(3.76)N2 → 2CO2 + 3H2O + 13.16N2
where 2 carbon and 6 hydrogen atoms in ethane require 2 CO2 molecules and 3 H2O molecules, respectively, in
the products. There are then 7 oxygen atoms in the products, which implies 3.5 oxygen molecules in the
reactants. This in turn dictates the presence of (3.5)(3.76) = 13.16 nitrogen molecules in both the reactants and
products.
The reaction equation then indicates that 3.5(1 + 3.76) = 16.66 moles of air are required for complete
combustion of one mole of ethane.
In Table 3.5, the molecular weight of the gas mixture, 18.169, is found in the fourth column by summing the
products of the mole fractions of the fuel components and the component molecular weights. This is analogous
to the earlier determination of the average air molecular weight from the nitrogen and oxygen mixture mole
fractions.
The products of the mole fractions of fuel components and the moles of air required per mole of fuel component
(as determined earlier and tabulated in the fifth column of Table 3.5) then yield the moles of air required for
each combustible per mole of fuel (in the sixth column). Summing these, the number of moles of air required
per mole of fuel yields the stoichiometric mole air-fuel ratio, 9.114.
The stoichiometric mass A/F is then given by the mole A/F times the ratio of air molecular weight to fuel
molecular weight: (9.114)(28.9)/18.169 = 14.5.
Heat Transfer in a Chemically Reacting Flow; open systems
Consider now the combustion problem in which fuel and oxidizer flow into a control volume and combustion
products flow out. The steady-flow First Law of Thermodynamics applied to the control volume may be written
as
Q = Hp - Hr + Ws
[Btu | kJ]
(4.14)
where Q is heat flow into the control volume, Ws is the shaft work delivered by the control volume, and the
enthalpies, H, include chemical as well as thermal energy. The subscripts r and p refer to the reactants entering
and products leaving the control volume, respectively. The enthalpy Hp is the sum of the enthalpies of all
product streams leaving the control volume. A similar statement applies to Hr for the entering reactant streams.
The individual enthalpies may each be written as the product of the number of moles of the component in the
reaction equation and its respective enthalpy per mole of the component. For example, for k products:
Hp = n1h1 + n2h2 +...+ nkhk
[Btu | kJ]
)
where the n.s are the stoichiometric coefficients of the chemical equation for the combustion reaction, and the
enthalpies are on a per-mole bases. The same applies for the reactants and Eq. (4.14) can be rewritten as:
Where m is the mass and h is the specific enthalpy of each constituent on a mass basis.
Consider, for example, the complete combustion of ethane:
The enthalpy of any component of the reactants or products may be written as the sum of (1) its enthalpy of
formation at the standard temperature, To=25ºC, and standard pressure, and (2) its enthalpy difference between
the actual state and the standard state of the components. Thus, for each component:
h(T) = hf (To) + [h(T) - h(To)]
[Btu /mole | kJ /mole]
Sensible heat is evaluated as cpΔT if cp is cte. Table 4-8 gives values of the enthalpies of formation of several
substances as a function of temperature. On a molar basis, equation 4.15 can be rewritten as:
Where n and M are the number of moles and molecular mass of each constituent, respectively. In combustion
reactions, ΔQ is referred to as Heating Value of the fuel.
Closed systems:
Equation 4.14 is still valid but with a non-flow work term:
Wnf is non-flow work; for ideal gases we can use the relation:
So we obtain a modified form of Eq. 4.17:
Writing ΔQ=HV:
And since Tp=Tr= Ti
HVnf is also called the internal energy of combustion.
Heat of Combustion and Heating Value
The heat of combustion, or enthalpy of combustion, of a fuel is defined as the energy transferred during a
steady-flow process in which the fuel is completely burned and where the products are returned to the
temperature and pressure of the reactants.
It is given in Btu/lbm or in J/kg of fuel on two basis:
 As received, dry
 Dry and ash free
The negative of the enthalpy of combustion of a fuel burned in air is usually referred to as the heating value of
the fuel. When water in the combustion products is condensed, the heat of vaporization of the water adds to the
chemical energy released, and the resulting heating value is called the higher heating value, HHV. The heating
value obtained when the product water stays a vapor is called the lower heating value, LHV. The difference
between the two is given by:
The partial pressure of water vapor in the products is obtained by multiplying the total pressure by the mole
fraction of H2O. In the above equations, the number 9 represents the mass of H2O obtained from a unit mass of
H2 in the fuel.
Because water is usually in vapor form in combustion gases, it seems more appropriate to use the LHV for
efficiency and energy balance calculations. But the American standard is to use the HHV whereas the LHV is
the European standard.
Heating values are usually tabulated at sandar temperature (25 ºC or 77ºF) ; considering a system with no shaft
work exchange, Eq. 4.17 leads to:
Note that writing the combustion equation with N2 does not alter the result since it is on both sides at the same
temperature. Note also that the same results are obtained for stoichiometric and lean mixtures as long as the
combustion is considered complete.
Examples from: Yunus A. Cengel and Michael A. Boles “Thermodynamics: An Engineering Approach”; 6th
Edition, McGraw Hill, 2007.
4-8 Combustion temperature or flame temperature:
The flame temperature (or combustion temperature) can be calculated by performing the same energy balance
used for calculating the heat of combustion (or HV). But, the heating value is considered known (or obtained
from tables), as well as any heat transfer from or to the system, and the final temperature is the unknown.
But it should be noted that since the heats of formation needed in the computations depend on the temperature
of the products (which is the unknown temperature to be computed), a trial and error procedure (iterations) is
needed to solve the problem. This can be avoided if cp of the products is considered constant.
The adiabatic flame temperature:
In the case of no heat loss to the surroundings and no work interaction (Q =W= 0), the temperature of the
combustion products reaches a maximum, which is called the adiabatic flame or adiabatic combustion
temperature of the reaction
Once the reactants and their states are specified, the enthalpy of the reactants Hreact can be easily determined.
The temperature of the products is not known prior to the calculations. Therefore, the determination of the
adiabatic flame temperature requires the use of an iterative technique unless equations for the sensible enthalpy
changes of the combustion products are available.
When the oxidant is air, the product gases mostly consist of N2, and a good first guess for the adiabatic flame
temperature is obtained by treating the entire product gases as N2.
The adiabatic flame temperature of a fuel is not unique and depends on:
 the state of the reactants
 the degree of completion of the reaction
 the amount of air used
From example 4.4, we see that a lean mixture yield a lower flame temperature because of the dilution effect of
the excess air. A rich mixture also gives a lower temperature because of incomplete combustion and the
maximum temperature is obtained for stoichiometric conditions. A higher temperature is obtained if pure
oxygen is used instead of air.
The adiabatic flame temperature is obtained by setting Q=W=0 in Eq. 4.17 :
4.9 ENERGY PERFORMANCE ASSESSMENT OF BOILERS
Performance of the boiler, like efficiency and evaporation ratio reduces with time, due to poor combustion, heat
transfer fouling and poor operation and maintenance. Deterioration of fuel quality and water quality also leads
to poor performance of boiler. Efficiency testing helps us to find out how far the boiler efficiency drifts away
from the best efficiency. Any observed abnormal deviations could therefore be investigated to pinpoint the
problem area for necessary corrective action. Hence it is necessary to find out the current level of efficiency for
performance evaluation, which is a pre requisite for energy conservation action in industry.
Purpose of the Performance Test


To find out the efficiency of the boiler
To find out the Evaporation ratio
The purpose of the performance test is to determine actual performance and efficiency of the boiler and
compare it with design values or norms. It is an indicator for tracking day-to-day and season-to-season
variations in boiler efficiency and energy efficiency improvements
Performance Terms and Definitions
Scope
The procedure describes routine test for both oil fired and solid fuel fired boilers using coal, agro residues etc.
Only those observations and measurements need to be made which can be readily applied and is necessary to
attain the purpose of the test.
Reference Standards
ASME Standard : PTC-4-1 Power Test Code for Steam Generating Units
Part One : Direct method (also called as Input -output method).
Part Two : Indirect method (also called as Heat loss method)
The Direct Method Testing
Description
This is also known as „input-output method‟ due to the fact that it needs only the useful output (steam) and the
heat input (i.e. fuel) for evaluating the efficiency. This efficiency can be evaluated using the formula:
Direct Method Testing
Measurements Required for Direct Method Testing
Heat Input
Both heat input and heat output must be measured. The measurement of heat input requires knowledge of the
calorific value of the fuel and its flow rate in terms of mass or volume, according to the nature of the fuel.
For Gaseous Fuel
A gas meter of the approved type can be used and the measured volume should be corrected for temperature and
pressure. A sample of gas can be collected for calorific value determination, but it is usually acceptable to use
the calorific value declared by the gas suppliers.
For Liquid Fuel
The meter, which is usually installed on the combustion appliance, should be regarded as a rough indicator only
and, for test purposes, a meter calibrated for the particular oil is to be used and over a realistic range of
temperature should be installed. Even better is the use of an accurately calibrated day tank.
For Solid Fuel
The accurate measurement of the flow of coal or other solid fuel is very difficult. The measurement must be
based on mass, which means that bulky apparatus must be set up on the boiler-house floor. Samples must be
taken and bagged throughout the test, the bags sealed and sent to a laboratory for analysis and calorific value
determination. In some more recent boiler houses, the problem has been alleviated by mounting the hoppers
over the boilers on calibrated load cells, but these are yet uncommon.
Heat Output
There are several methods, which can be used for measuring heat output. With steam boilers, an installed steam
meter can be used to measure flow rate, but this must be corrected for temperature and pressure. In earlier years,
this approach was not favored due to the change in accuracy of orifice or venturi meters with flow rate. It is now
more viable with modern flow meters of the variable-orifice or vortex-shedding types.
The alternative with small boilers is to measure feed water, and this can be done by previously calibrating the
feed tank and noting down the levels of water during the beginning and end of the trial. Care should be taken
not to pump water during this period. Heat addition for conversion of feed water at inlet temperature to steam, is
considered for heat output.
In case of boilers with intermittent blowdown, blowdown should be avoided during the trial period. In case of
boilers with continuous blowdown, the heat loss due to blowdown should be calculated and added to the heat in
steam.
Merits and Demerits of Direct Method
Merits
a) Plant people can evaluate quickly the efficiency of boilers.
b) Requires few parameters for computation.
c) Needs few instruments for monitoring.
Demerits
a) Does not give clues to the operator as to why efficiency of system is lower.
b) Does not calculate various losses accountable for various efficiency levels.
c) Evaporation ratio and efficiency may mislead, if the steam is highly wet due to water carryover
The Indirect Method Testing
Description
The efficiency can be measured easily by measuring all the losses occurring in the boilers using the principles to
be described. The disadvantages of the direct method can be overcome by this method, which calculates the
various heat losses associated with boiler. The efficiency can be arrived at, by subtracting the heat loss fractions
from 100.
An important advantage of this method is that the errors in measurement do not make significant change in
efficiency. Thus if boiler efficiency is 90%, an error of 1% in direct method will result in significant change in
efficiency, i.e. 90 ± 0.9 = 89.1 to 90.9. In indirect method, 1% error in measurement of losses will result in
Efficiency = 100 – (10 ± 0.1) = 90 ±0.1 = 89.9 to 90.1
Boiler efficiency by the Indirect Method is performed using the BS 845 / ASME PTC 4.1 standards. The
various heat losses occurring in the boiler are
Efficiency = 100 – (1 + 2 + 3 + 4 + 5 + 6 + 7 + 8) (by indirect method)
Indirect Method Testing
The following losses are applicable to liquid, gas and solid fired boiler :
L1 – Loss due to dry flue gas (sensible heat)
L2 – Loss due to hydrogen in fuel (H2)
L3 – Loss due to moisture in fuel (H2O)
L4 – Loss due to moisture in air (H2O)
L5 – Loss due to carbon monoxide (CO)
L6 – Loss due to surface radiation, convection and other unaccounted*.
*Losses which are insignificant and are difficult to measure.
The following losses are applicable to solid fuel fired boiler in addition to above:
L7 – Unburnt losses in fly ash (Carbon)
L8 – Unburnt losses in bottom ash (Carbon)
Boiler Efficiency by indirect method = 100 – (L1 + L2 + L3 + L4 + L5 + L6 + L7 + L8)
Energy Balance
Having established the magnitude of all the losses mentioned above, a simple energy balance would give the
efficiency of the boiler. The efficiency is the difference between the energy input to the boiler and the heat
losses calculated.
Combustion Rate
Combustion rate is determined by the rate at which parcels of unburned gas are broken down into smaller ones
(create sufficient interfacial area between unburned mixture & hot gases to enable reaction)
Factors Affecting Boiler Performance
The various factors influencing the boiler performance are listed below:
a.
b.
c.
d.
e.
f.
g.
h.
i.
Periodical cleaning of boilers
Periodical soot blowing
Proper water treatment program and blow down control
Draft control
Excess air control
Percentage loading of boiler
Steam generation pressure and temperature
Boiler insulation
Quality of fuel
All these factors individually/combined, contribute to the performance of the boiler and reflected either in boiler
efficiency or evaporation ratio. Based on the results obtained from the testing further improvements have to be
carried out for maximizing the performance. The test can be repeated after modification or rectification of the
problems and compared with standard norms. Energy auditor should carry out this test as a routine manner once
in six months and report to the management for necessary action.
Boiler Terminology
MCR: Steam boilers rated output is also usually defined as MCR (Maximum Continuous Rating). This is the
maximum evaporation rate that can be sustained for 24 hours and may be less than a shorter duration maximum
rating.
Boiler Rating
Conventionally, boilers are specified by their capacity to hold water and the steam generation rate. Often, the
capacity to generate steam is specified in terms of equivalent evaporation (kg of steam/hour at 100 ºC).
The equivalent of the evaporation of 1 kg of water at 100 ºC to steam at 100 ºC.
Efficiency
In the boiler industry there are four common definitions of efficiency:
Combustion Efficiency
Combustion efficiency is the effectiveness of the burner only and relates to its ability to completely burn the
fuel. The boiler has little bearing on combustion efficiency. A well-designed burner will operate with as little as
15 to 20% excess air, while converting all combustibles in the fuel to useful energy.
Thermal Efficiency
Thermal efficiency is the effectiveness of the heat transfer in a boiler. It does not take into account boiler
radiation and convection losses.
Boiler Efficiency
The term boiler efficiency is often substituted for combustion or thermal efficiency. True boiler efficiency is the
measure of fuel to steam efficiency.
Fuel to Steam Efficiency
Fuel to steam efficiency is calculated using either of the two methods as prescribed by the ASME (American
Society for Mechanical Engineers) power test code, PTC 4.1. The first method is input output method. The
second method is heat loss method.