34

CHAPTER 3

COMBUSTION MONITORING SETUP AT POWER

STATION

3.1 INTRODUCTION TO COMBUSTION MONITORING

The combustion condition monitoring involves boiler performance

and optimization. The necessity to monitor the condition of the flame as

discussed by Lu Gilabert et al (2005) is to control emissions of nitrogen oxide

(NOx), Carbon monoxide (CO), increased fuel efficiency and improved

burner reliability which are to maintain the required furnace temperature. The

flue gas emissions are increased at the outlet when the air to fuel ratio is

incorrect. This condition in turn influences the combustion quality.

The function of the flame monitoring technique incorporates a

virtual flame detector to identify non firing burners, a flame monitor with

adjustable memory, and a flame analyzer to determine the combustion status

of each burner. This sensing function is designed to provide guidance for

balancing air/fuel ratio between individual burners in a multi burner furnace

system with individual burner control capability.

The systems based on the latest optical sensing and digital image

processing techniques, are capable of determining geometric (size and

location), where the geometry of the burner is fixed for luminous (brightness

and uniformity) and fluid dynamic (temperature and flicker frequency)

35

parameters of a flame. The systems are evaluated both on the laboratory and

industrial scale combustion rigs for a variety of operating conditions.

3.2 OBJECTIVE OF COMBUSTION

The objective of combustion is to retrieve energy by burning the

fuel in the most efficient possible way. To maximize combustion efficiency, it

is necessary to burn all the fuel material with least amount of losses. The

complete burning of fuels leads to energy efficient and economical

combustion process.

3.2.1 Complete Combustion

Complete combustion occurs when 100% of the energy in the fuel

is extracted. It is important to strive for complete combustion to preserve the

fuel and provide a cost effective combustion process. There must be enough

air in the combustion chamber for complete combustion to occur. The

addition of excess air greatly lowers the formation of CO (carbon monoxide)

by allowing CO to react with O2. The presence of smaller amounts of CO

remaining in the flue gas indicates that the combustion process is closer to

complete combustion. This is because the toxic gas like carbon monoxide

(CO) still contains a very significant amount of energy that should be

completely burnt. Combustion process can be made complete if

stoichiometric combustion takes place which is an ideal case.

3.3 FUEL

There are many fuels currently used in combustion processes

throughout the world, the most common are coal, oils, diesel oil, gasoline,

natural gas, propane, coke oven gas, and wood. Each fuel has different

chemical characteristics including, a unique carbon to hydrogen ratio, and

36

calorific value. The amount of combustion air completely required to

completely burn a specific fuel will depend on those characteristics especially

the carbon to hydrogen ratio. The higher the carbon content in the fuel, the

more air required to achieve complete combustion. When monitoring the

efficiency of a combustion process, it is important to know the fuel being

burnt since this information will help not only to determine the boiler’s

optimal working conditions but also to maximize the boiler’s efficiency.

3.4 EFFECT OF BURNING COAL AND OIL

3.4.1 Coal

There are many varieties of coal being used in combustion process

around the world; the most widely used are anthracite, bituminous, sub-

bituminous, and lignite. Asri Gani et al (2005) have stated that the quality of

coal is dependent on the carbon content which inturn affects the quality of

combustion. When coal is burnt a considerable amount of carbon dioxide is

generated as there is extremely high level of carbon in coal which requires

more oxygen and more combustion air to burn coal comparing to other

fossil fuels. In addition to the carbon dioxide emissions, burning the coal

produces some other pollutants including NOx, sulphur dioxide (SO2), sulphur

trioxide (SO3), and particulate emissions. The sulphur dioxide chemically

combines with water vapour in the air to produce a dilute form of sulphuric

acid, which is one of the main causes of acid rain. The coal from the coal

feeders are crushed finely and preheated so as to supply pulverized coal to the

furnace. The coal or lignite is supplied by the conveyor belt as shown in

Figure 3.1.

37

Figure 3.1 Lignite extraction feeder and belt conveyor system (Courtesy, NLC)

38

3.4.2 Oil

The oil fuels are mostly a mixture of very heavy hydrocarbons,

which have higher levels of hydrogen than those found in coal. At the same

time, oil contains less carbon than coal and therefore requires less combustion

air to achieve complete combustion. Therefore, burning the oil releases less

carbon dioxide than burning the coal and more carbon dioxide than burning

the natural gas. Most of the pollutants produced when burning coal are also

the by-products of burning the oil.

3.4.3 Air Flow

It is fundamental to maintain appropriate airflow in combustion

process so as to ensure safe and complete combustion. The total airflow

includes combustion air, infiltration air and dilution air.

3.4.4 Combustion Air

The combustion air is actually used to burn the fuel.

3.4.5 Infiltration Air

Infiltration air is the outdoor air that is not deliberately remains in

the boiler. Sources of infiltration air may be by means of cracks or leaks.

3.4.6 Dilution Air

The dilution air combines with the flue gases and lowers the

concentration of the emissions. There are two types of dilution air, i.e., natural

and induced (artificially created). The process of combustion is a high speed,

high temperature chemical reaction which occurs when the elements in a fuel

combine with oxygen and produce heat. All fuels, whether they are solid,

39

liquid or in gaseous form, consists primarily the compounds of carbon and

hydrogen called hydrocarbons. Sulphur is also present in these fuels.

The combustion is a rapid chemical reaction of two or more

substances with a characteristic liberation of heat and light which is

commonly called as burning. The burning of a fuel (e.g., wood, coal, oil, or

natural gas) in the presence of air is a familiar example of combustion

process. Combustion need not involve oxygen; e.g., hydrogen burns in

chlorine to form hydrogen chloride with the liberation of heat and light which

denotes the characteristic of combustion. Before a substance burns, it must be

heated to its ignition point. Pure substances have ignition points based on

their characteristics.

The burning of any substance, in gaseous, liquid or solid form is

called as combustion process. In its broad definition, combustion includes fast

exothermic chemical reactions, generally in the gas phase but not excluding

the reaction of solid carbon with a gaseous oxidant. Flames represent

combustion reactions that can propagate through space at subsonic velocity

and are accompanied by the emission of light. The flame is the result of

complex interactions of chemical and physical processes whose quantitative

description must draw on a wide range of disciplines such as chemistry,

thermodynamics, fluid dynamics and molecular physics. In the course of the

chemical reaction, energy is released in the form of heat, atoms and free

radicals with the generation of all highly reactive intermediates of the

combustion reactions.

When the hydrogen and oxygen combine, intense heat and water

vapour is formed. When carbon and oxygen combine, intense heat and the

compounds of carbon monoxide or carbon dioxide are formed. The

combination of sulphur and oxygen leads to the formation of sulphur dioxide

and heat. These chemical reactions take place in a furnace during the burning

40

of the fuel, provided there is sufficient air (oxygen) to completely burn the

fuel. Very little of the released carbon is actually consumed in the combustion

reaction because the flame temperature seldom reaches the vaporization point

of carbon. Most of it combines with oxygen to form CO2 and passes out

through the vent. Carbon, which cools before it can combine with oxygen to

form CO2, passes out the vent as visible smoke. The intense yellow colour of

an oil flame is largely caused by incandescent carbon particles.

3.5 EXISTING SETUP AT NEYVELI LIGNITE CORPORATION

(NLC)

The primary objective of this work is to develop an intelligent

combustion quality and flue gas monitoring system using flame image

analysis by colour image processing at the furnace level. Conventional

combustion control systems for multi burner furnaces rely on simplified

temperature measurement schemes away from the flame and monitoring of

excess O2, CO, CO2, NOx and SOx emissions. According to the brightness

value of flame image pixels, the combustion characteristic parameters are

picked up from the flame image. The online monitoring of combustion quality

and flue gas emissions using intelligent image processing technique thereby

automatic adjustment of air/fuel ratio can be achieved so as to ensure

complete combustion.

The boilers are steam generators which convert preheated water

into super heated steam. This high pressure super heated steam drives the

turbine coupled to a generator which in turn generates power. The Thermal

Power Station (TPS) Expansion-I at Neyveli (NLC) has two units with

generation capacity of 210MW each. The specifications of the boiler are

given in Table 3.1 and the general arrangements of the boiler at NLC is

shown in the Figure 3.2.

41

3.6 TANGENTIAL FIRING SYSTEM

The total height of the boiler is 90m and the entire firing process

gets over within 42m. The furnace is located at the 19 meter level of the boiler

where heavy oil is used for initial firing. Thereafter the firing process is

enhanced by using lignite as the fuel whose calorific value is 2350 kCal/kg

and fired at a rate of 189 to 230 t/hr. The firing system is called as tangential

firing system which includes six mills to crush the coal so that it becomes fine

powder. The chemical composition of the coal used is given in Table 3.2. The

coal is also preheated and it is used as pulverized coal whose quality is

dependent on the moisture and ash content. The tangential firing system is

shown in Figure 3.3.

Table 3.1 Boiler data at Neyveli Lignite Corporation

S.No Parameters Specifications

1. Type Radiant tower

2. Circulation Natural

3. Manufacture Ansaldo Energia

4. Boiler Design Pressure 182 kg/cm2(a)

5. Fuel Lignite

6. Start-up fuel Light Diesel Oil – Heavy Fuel oil

7. Burners type Tangential Firing

8. Number of burners 12 Lignite and 8 Fuel oil burners

9. Mills type Ventilation Mill MB 3400/900/490

10. Number of Mills 6 numbers

11. SH Flow at outlet 540 t/hr

12. Temperature SH at outlet 540 degree Celsius

13. Lignite fired-Best 189 t/hr

14. Lignite fired-Average 213 t/hr

15. Lignite fired-worst 230 t/hr

42

Table 3.2 Coal characteristics under normal operating conditions

S.No. Parameters Average Values

1. Net Calorific Value 2350 kcal/kg

2. Moisture (M) 52%

3. Ash (A) 6%

Combustible Substances

4. Carbon (C) 29.19%

5. Hydrogen (H) 2.02%

6. Sulphur (S) 1.0%

7. Nitrogen (N) 0.44%

8. Oxygen (O) 9.36%

9. Total (M+A+C+S+N+O) 100.0%

Figure 3.2 General Arrangements of a Boiler at NLC (Courtesy, NLC)

43

The existing setup at NLC has an infrared camera placed inside a

water cooled jacket with servo motor mechanism for retracting the same. The

video captured by the camera is displayed on the CRT monitor at control

room. The flame video displayed on the CRT monitor is used for identifying

the presence or absence of the flame to avoid explosion of the boiler. The

repeated loading of the furnace without monitoring the flame status causes

explosion of the boiler which is very dangerous. The Figure 3.4 shows the

block diagram for the existing flame monitoring set up at NLC.

Figure 3.3 Tangential firing system (Courtesy, NLC)

44

Figure 3.4 Schematic diagram for existing flame monitoring setup

3.7 FURNACE

An industrial furnace or direct fired heater is an equipment used to

provide heat for the combustion process or can serve as reactor which

provides heat for reaction. Furnace designs vary depending on its function,

heating purpose, type of fuel and method of introducing combustion air.

However, most process furnaces have some common features. The schematic

diagram of the furnace is shown in Figure 3.5.

Fuel flows into the burner and is burnt with air provided from an air

blower. There can be more than one burner in a particular furnace which can

be arranged in cells. This arrangement heats a particular set of tubes. Burners

can also be floor mounted, wall mounted or roof mounted depending on the

design considerations. The flames heat up the tubes, which in turn heats the

fluid inside in the first part of the furnace known as the radiant section or

firebox. In this chamber where combustion takes place, the heat is transferred

mainly by radiation to tubes around the fire in the chamber. The preheated

fluid passes through the tubes and is thus heated to the desired temperature.

The gases from the combustion process are known as the flue gases. After the

flue gas leaves the firebox, most furnace designs include a convection section

where more heat is recovered before venting it to the atmosphere through the

flue gas stack. The furnace data is given in Table 3.3.

45

Table 3.3 Parameters and data of the furnace at NLC

S.No Furnace parameters Furnace data

1. Type Dry bottom furnace

2. Depth 13m

3. Width 13m

4. Height 85m

5. Volume 14365m3

Figure 3.5 Schematic diagram of a furnace (courtesy, NLC)

In this chamber where combustion takes place, the heat energy

from the fuel is used to heat the secondary fluid with special additives like

antirust and high heat transfer efficiency. This Heated Transferred Fluid

(HTF) is then circulated round the whole plant to heat exchangers to be used

46

wherever heat is needed instead of directly heating the product line as the

product or material may be volatile or prone to cracking at the furnace

temperature.

3.8 NEED FOR STEAM AND ITS TEMPERATURE CONTROL

The rate at which heat is transferred to the fluid in the tube banks of

a boiler will depend on the rate of heat input from the fuel or exhaust from the

gas turbine. This heat will be used to convert water to steam and then to

increase the temperature of the steam in the superheating stage. In a boiler,

the temperature of the steam will also be affected by the pattern in which the

burners are fired since some of the tubes pick up heat by direct radiation from

the burners. In both types of plant, the temperature of the steam will also be

affected by the flow of fluid within the tubes and by the way in which the hot

gases circulate within the boiler. As the steam flow increases, the temperature

of the steam in the banks of tubes that are directly influenced by the radiant

heat of combustion starts to decrease as the increasing flow of fluid takes

away more of the heat that falls on the metal. Therefore the steam

temperature/steam flow profile shows a decline as the steam flow increases.

On the other hand, the temperature of the steam in the banks of tubes in the

convection passes tends to increase because of the higher heat transfer

brought about by the increased flow of gases, so that this temperature/flow

profile shows a rise in temperature as the flow increases. By combining these

two characteristics (the one rising and the other falling) the boiler designer

will aim to achieve a fairly flat temperature/flow characteristic over a wide

range of steam flow.

No matter how successfully this target is attained, it cannot yield an

absolutely flat temperature/flow characteristic. Without any additional

control, the temperature of the steam leaving the final super heater of the

47

boiler would vary with the rate of steam flow, following the 'natural

characteristic' of the boiler. The shape of this will depend on the particular

design of plant, but in general, the temperature will rise to a peak as the load

increases, after which it will fall. The steam turbine or the process plant that is

to receive the steam usually requires the temperature to remain at a precise

value over the entire load range, and it is mainly for this reason that some

dedicated means of regulating the temperature must be provided. Since

different banks of tubes are affected in different ways by the radiation from

the burners and the flow of hot gases, an additional requirement is to provide

some means of adjusting the temperature of the steam within different parts of

the circuit, to prevent any one section from becoming overheated.

The design of the plant should be targeted on arranging for the

natural characteristic to attain the correct steam temperature when the rate of

steam flow is such as to operate in normal mode. If this is possible, it means

that spray water is used only when the unit is being brought up to load or

when it operates at off design conditions. In practice this objective can be

attained only to a limited extent, because the boiler's natural characteristic

changes with time due to factors such as fouling of the metal surfaces, which

affects the heat transfer. In general, it is common to operate with continuous

spraying, which has the advantage of allowing the steam temperature to be

adjusted both upwards and downwards. If the required temperature is to be

met solely by employing the natural characteristic as described, it would not

be possible to produce temperature increase. The mechanisms which are

employed to regulate the temperature according to the controller's command

depends on whether the temperature of the steam is lowered below the

saturation point or not and the controlling devices are known as attemperator

or desuperheater.

48

3.9 CONTROL OF AIR TO FUEL RATIO

The fuel/air ratio is the lowest if excess air level (measure in

percent of oxygen O2) is present in the flue gas at a set firing rate without the

carbon monoxide (CO) being produced. At low firing rates; the burner design

requires more excess air to ensure the mixing of air with the fuel in proper

ratio. At higher firing rates there is enough differential pressure drop (burner

wind box to combustion chamber area) for the air to mix with the fuel. All

boilers have a fuel/air ratio curve and it is extremely important that the plant

has this documented information. In other words ratio control is adopted to

maintain the air fuel ratio. The air to fuel ratio is the proportion of air to fuel

supplied during combustion process. The optimal ratio (the stoichiometric

ratio) occurs when all the fuel and oxygen in the reaction chamber balance

each other perfectly. Rich burning occurs when there is more fuel than air in

the combustion chamber while lean burning occurs when there is more air and

less fuel in the combustion chamber. The DCS display is available for the air

to fuel ratio control so as to ensure complete combustion and the quality of

combustion is judged manually out of experience.

The fuel and air quantities are manually adjusted. Chris Carter et al

(2003) suggested that either the gain or the bias is altered to change the

combustion conditions. With such systems, if the adjustment factor is set

wrongly or if changes outside the system dictate that the fuel/air ratio should

be altered, no provision exists for automatic correction and the right

combustion conditions can only be restored by manual intervention. To

improve performance and safety, some form of automatic recognition and

correction of these factors would be preferable. If the fuel/air ratio is

incorrect, combustion of the fuel will be affected and the results will be

observable in the flue gases. This indicates that an effective way to optimize

the combustion process is to change the fuel/air ratio automatically in

response to measurements of the flue gas content. For all fossil fuel boilers,

49

the oxygen content of the flue gases increases as the excess air quantity is

increased, while the carbon dioxide and water content decreases. Enrique

Teruela et al (2005) stated that the carbon monoxide content of the boiler's

flue gas is a direct indication of the completeness of the combustion process

and the system based on the measurement of this parameter has been

recognized as an effective mechanism for improving combustion performance

in coal and oil fired boiler plant.

Measurement of the flue gas and oxygen content often provides a

good indication of combustion performance, but it must be appreciated that

the presence of 'tramp air' due to leakages into the combustion chamber can

lead to anomalous readings. In the presence of significant leakage, reducing

the air/fuel ratio to minimize the flue gas and oxygen content can result in the

burners being starved of air. This is an area where systems based on carbon

monoxide measurements provide better results since the carbon monoxide

content of the gases is a direct indication of combustion performance and is

unaffected by the presence of tramp air. A system which adjusts the fuel/air

ratio in relation to the flue gas oxygen content is shown in Figure 3.6.

The oxygen measurement is fed to a controller whose output

adjusts the fuel/air ratio by varying the multiplying factor of a gain block. The

transmitters used for measuring the flue gas and oxygen are usually based on

the use of zirconium probes whose conductivity is affected by the oxygen

content of the atmosphere in which they are installed. Nowadays true two

wire 4-20 mA analyzers are available. The flue gases leave the combustion

chamber through ducts of considerable cross sectional area and it is inevitable

that a significant degree of stratification will occur in the gases as they flow to

the chimney. Air entering the furnace through the registers of idle burners will

tend to produce higher oxygen content in the gases flowing along one area of

the duct than will be present in another area, where fewer burners may be idle.

It is therefore necessary to take considerable care that any gas analysis

50

provides a truly representative sample of the average oxygen content, and this

demands that great care should be exercised over the selection of the location

of the analyzer. With larger ducts it may be necessary to provide several

analyzers. The signals from these analyzers can be combined, or the operator

can be given the facility to select one or more signals for use.

Figure 3.6 Air/Fuel ratio control with oxygen trimming mechanism

3.9.1 Milling System for Lignite Supply

The location of the lignite mills that supply finely powdered

preheated coal to the furnace at NLC is shown in the Figure 3.7. The initial

firing is done using oil which is supplied from the oil tank. The coal is

preheated using the heat energy extracted from the flue gases. The lignite is

fed into the mills at the end of the resuction duct. As the lignite inherently has

moisture of more than 40%, the flue gas from the boiler at a temperature of

800 degree Celsius is sucked into the mills through rescution duct, there by

51

absorbing the moisture before the coal being pulverized to the micron level.

The pulverized fuel is fed into the furnace through coal burner valves. The

lignite burner mouth is provided at two levels of 19 m level and 21 m level.

Figure 3.7 Milling system to pulverise the Lignite (Courtesy, NLC)

52

The oil tank along with the oil coolers is provided for lubrication of

the milling system. The hot sealing air is provided for sealing the mills to

prevent any problems due to buffing. The service water provided is for the

safety of the mills so as to encounter the rise in temperature at the inside of

the mills.

The supply lines include heavy oil inlet, outlet, light fuel oil,

atomizing steam, service air, cooling air to flame scanners and burners. The

parameters include design pressure, design temperature, operating pressure,

operating temperature and flow. The cooling air also supplied to keep the

flame scanners so as to keep them cool. This arrangement will not only

increase the life time of the flame scanners and but also prevent them from

excessive heat.

3.9.2 Air Supply for Combustion Process

The coal is obtained from the coal mines at Neyveli. The coal is

crushed into fine powder in the mills and is preheated. The coal stored in the

bunker is transported to the coal mills through the conveyor belt. There are six

mills namely A, B, C, D, E and F placed tangentially at two levels (19 meter

level and 21 meter level). Nearly 9000 to 10,000 kg of coal is fed into the

hearth of the furnace every day. The fine powdered coal is then sent to the

Electrostatic Precipitator (ESP) for removal of any fine metallic dust particles

present in it. It is then preheated so that the pulverized coal is fed to the hearth

of the furnace which yields better heat energy when compared to the coal

lumps. The diagram in Figure 3.8 depicts the combustion air for Lignite and

oil firing system.

53

Figure 3.8 Combustion air supply for lignite and oil firing system

(Courtesy, NLC)

The oil firing system (black coloured line) comprises of eight

burners at two levels (one at 19 m level and the other at 21 m level). Light

Diesel Oil (LDO) or Low Sulphur Heavy Stock (LSHS) is used for intital

firing followed by lignite firing. The combustion air for lignite comprises of

primary air, secondary air and the teritary air.

54

The primary air (red coloured line) is used for the control of the

inlet temperature to the mill. In addition to this for the temperature control

inside the mill, attemperator is used for spraying the cold water on the flue

gas. The line from the attemperator is shown in blue colour. The same gas is

also used for sealing the mouth of the lignite burner.

The secondary air (pink coloured line) indicates the combustion of

the lignite. A part of this air is used in AAF (Additional Air Port) which is

indicated as over fire air port. This air enables complete combustion.

The green coloured line is the hot sealing air to prevent buffing of

the mill as explained earlier in the milling system.

3.10 OIL CONTROL

The oil control contains the LSHS and LDO flow control. The LDO

flow control is designed to maintain the proper flow to oil burners satisfying

the boiler demand; the control philosophy is based on simple feedback closed

control loop limited by the output signal of LDO pressure at burners control

loop. Similarly the LSHS flow control is designed to maintain the proper flow

to oil burners satisfying the boiler demand. The control philosophy is based

on the simple feedback closed loop control limited by the output signal of

LSHS at the control loop of the burners.

3.10.1 LSHS and LDO Flow Control

A low selecting logic compares the boiler firing rate (demand

signal), generated by Unit Coordinator logic, to the total boiler combustion air

flow signal (measured at RAHs outlet, upstream the common header), the

lowest of them, deducted by coal flow (if any) via another low selecting logic

and compared to the Secondary Air (SA) flow to the signal of the oil burners,

55

the lowest of them becomes the total oil flow demand, common to LSHS and

LDO control loops. The result is that the total fuel demand is limited to the

level of the signal representing available total air flow and that of the set point

of the oil flow which is limited to the level of the signal representing the

available secondary air flow to oil burners.

The total oil flow demand, deducted by LDO flow signal becomes

the set point of the LSHS flow controller which is compared to its flow

measurement and through a dedicated controller sets the demand for the

LSHS control valve.

The flow control valve of LSHS is positioned by a high selecting

logic that compares the output signal of flow controller to the output signal of

pressure controller; the highest of them becomes the actual position demand

for the LSHS flow control valve. The loop will be forced to manual operation

if no burner is in service with LSHS or if one or the other fuel masters (LDO

coal) is in automatic mode.

As soon as the LSHS main trip valve opens the control valve will

be forced to fixed open position until the first LSHS burner is in operation and

then the LSHS flow control loop will be released to auto mode. For boiler trip

the total oil flow demand is forced to zero value and thus the LSHS control

valve will close.

The LDO flow control is designed to maintain the proper flow to

oil burners satisfying the boiler demand; the control philosophy is based on

simple feedback closed control loop limited by the output signal of LDO

pressure at burners control loop.

56

The total oil flow demand, deducted by LSHS flow signal, becomes

the set point of the LDO flow controller that is compared to its flow

measurement and through a dedicated controller sets the demand for the LDO

control valve.

To avoid that flames to active burners can be lost due to LDO low

pressure i.e. control valve too much closed, a high selecting logic compares

the output signal of flow controller to the output signal of pressure controller

and the highest of them becomes the actual position demand for the LDO

flow control valve.

The loop will be forced to manual if no burner is in service with

LDO or if one of the other fuel master (LSHS and coal) is in automatic mode.

As soon as the LDO main trip valve opens the control valve will be

forced to fixed open position until the first LDO burner is in operation and

then the LDO flow control loop will be released to auto mode. For boiler trip

the total oil flow demand is forced to zero value and thus the LDO control

valve will close.

3.10.2 Atomizing Steam Pressure Control

The atomizing steam pressure control is a simple feedback closed

control loop designed to maintain a steam constant pressure to oil burners to

allow a good combustion. The set point is computed as a function of burner

load and is manipulated by the operator via a biasing capability.

The set point is compared to atomizing steam pressure value and

through the controller sets the demand for the related control valve.

57

3.11 AIR CONTROL

3.11.1 Secondary Air to Oil Burners Flow Control

The Secondary Air (SA) to oil burners flow control is designed to

maintain the proper flow to oil burners satisfying the boiler demand, the

control philosophy is a simple feedback closed control loop.

A high selecting logic compares the boiler firing rate demand

signal, generated by Unit Coordinator logic deducted by coal flow (if any), to

the total oil flow signal, the highest of them becomes the SA to oil burners

flow demand (set point); the result is that SA flow demand is limited to (not

lower than) the level of the signal representing available oil flow.

The SA to oil burner’s set point is compared to the flow

measurement and through the dedicated controller sets the SA total flow

demand for all the oil burners in service.

Since each oil burner is equipped with its SA control damper, the

SA flow demand is multiplied by 8 (total number of oil burners) and divided

by the number of oil burners in service, so the gain of the total loop doesn’t

depend on the number of burners in service.

Proper firing action is performed according to the request from the

burner management system which forces air and flue gases. The positioning

of the oil burners and SA control dampers are as follows

minimum position for cooling; it means that, when related

burner is out of service, the damper will be almost quite closed

partially open (approx. 30%) to guarantee minimum combustion

air flow rate to perform furnace purge sequence

58

last position for five minutes if the combustion air flow is below

the purge rate at the time of the trip, waiting time for purge

fully open for natural draft requirement

One for each burner, i.e. eight, slave control loops are provided,

receiving the same flow demand from the unique master loop. Each slave

loop is provided with independent biasing capability by the operator.

3.12 EXCESS OXYGEN CONTROL

If only the amount of theoretical air are furnished some fuel would

not burn, therefore to assure a complete combustion additional combustion air

has to be furnished; the additional amount of combustion air is called excess

air, and it is evaluated by the oxygen percentage not used that leaves the

boiler in the flue gases.

So the oxygen trim control loop is used to calibrate continuously

the combustion air flow demand; the O2 percentage set point is a function of

the boiler load (SH steam flow) and the operator has a biasing capability to

shift the O2 percentage set point curve up or down of the established curve

based on boiler test. The O2 percentage set point is compared to the analyzer

output signal and through a dedicated controller sets the oxygen percentage

correction, which is sent to the air master. In order to avoid wind up, the

integral action is blocked if the air master is in manual mode. At the output of

the oxygen trimming control high and low limits are provided. The

arrangement of an oxygen analyzer is shown in Figure 3.9.

The oxygen measurement is fed to a controller whose output

adjusts the fuel/air ratio by varying the multiplying factor of a gain block. The

transmitters used for measuring flue-gas oxygen are usually based on the use

of zirconium probes, whose conductivity is affected by the oxygen content of

59

the atmosphere in which they are installed. True two wire 4-20 mA analyzers

are now available and both are accurate and reliable.

Figure 3.9 Arrangement of Oxygen analyzer

3.13 COAL MASTER CONTROL

The control loop of the coal master is devoted to develop the total

coal demand. A low selecting logic compares the boiler firing rate demand

signal, generated by unit coordinator logic, to the total boiler combustion air

flow signal, the lowest of them, deducted by total oil flow (if any), becomes

the set point of the coal master controller; the result is that the total fuel

demand is limited to the level of the signal representing the availability of the

total air flow.

60

The coal demand is compared to the total coal flow measurements

and through a dedicated controller sets the demand for all mills (coal total

demand), i.e. the output signal of the coal master control station. In order to

obtain the coal demand to each mill, the total demand of the coal is multiplied

by 4 (because the mill coal rate can be achieved by 4 mills at full load); the

resulting signal is subtracted from the rate of coal supplied to the mills and

this ratio by the number of mills in service and in automatic mode; the result

is that the gain of the total loop which does not depend on the number of mills

in service and that each mill mode (automatic / manual) toggling is bumpless.

The loop will be forced to manual if no mill is in service (and in

automatic mode) or if one the other fuel masters (LSHS - LDO) is in

automatic mode.

In order to compensate for inaccuracy in speed of the coal feeders,

the coal flow signal is calibrated by means of the heat release, calculated by

using the boiler as a calorimeter, taking into consideration superheated steam

flow (pressure and temperature compensated), drum pressure and feed water

temperature (total boiler heat release) deducting of the amount due to total oil

flow, thus representing the heat release by coal as fuel. The time function is

taken into consideration and the delay due to the grinding and coal

transportation. For boiler trip, the total coal demand is forced to zero.

3.14 MILL COAL RATE CONTROL

Six of the hereinafter control loops are provided, one for each mill.

Each individual mill coal rate control consists of the control loop that

regulates related coal feeders and the conveyor belt speed.

61

3.14.1 Coal Rate Control

The coal rate control loop is a simple feedback control. To improve

the response of the mill a dynamic action on coal demand to mill is added, as

described here in Equation (3.1)

1

2

1 sTY(s) U(s)

1 sT (3.1)

where U(s) is coal demand to each mill in the frequency domain;

Y(s) is coal feeders rate demand, in the frequency domain;

1 2T T , in order to have a demand amplification during transient.

The resulting rate demand of the coal feeder rate demand, biased if

any by the operator, is compared to mill coal feeder rate (i.e. coal volume);

the error through a dedicated controller sets the total coal demand, which is

sent to.

When the mill outlet temperature exceeds the operating value, but

below the trip value, the characterized signal of the mill outlet temperature

will be deducted to coal feeders rate demand (i.e. set point) trying to get back

the mill outlet temperature within the range.

The loop is forced to manual if both the coal feeders control loop

and the belt conveyor speed control loop are selected in manual mode. If mill

motor current absorption is low, the loop control output (mill coal demand)

cannot decrease; if mill motor current absorption is high, the coal demand

cannot increase. If only one coal feeder is in service, the mill coal demand is

limited at 50%, as mill full load can be reached by 2 feeders at full speed.

62

3.14.2 Coal Feeder Control

The total demand of the coal feeders is multiplied by 2 (number of

feeders at full speed required for full mill load) and the ratio of number of

coal feeders in service, so that the gain of the total loop does not depend on

the number of feeders which are under operation.

The resulting signal, via a high selecting logic, is compared to the

minimum speed of the coal feeder so as to avoid the amount of coal

transported to the mills, droping below the minimum, causing flame

instability.

The secondary air control in automatic mode, the proper sub-

stoichiometic ratio between coal and air are the two important factors

governing the combustion process. If the mill control or secondary air control

is in manual mode, the speed demand of coal feeder is limited by the available

secondary and primary air flow.

Then the output signal of the above logic, via low selecting logic, is

compared with the speed of the conveyor belt (taking into account the number

of feeders in service) so that the coal feeder speed cannot increase beyond the

speed of the conveyor belt, avoiding abnormal coal accumulation on the

conveyor belt.

The resulting speed demand is sent to three coal feeders. Each

speed demand is forced to zero if the related feeder is not in service and

forced to a proper prefixed value at the feeder start up.

63

3.15 AIR FLOW CONTROL TO COAL MILLS

The air flow control to the coal mills includes Primary Air (PA),

Secondary Air (SA) and Tertiary Air (TA) flow control. Six of the control

loops are provided, one for each mill. The secondary air flow control is

designed to maintain the air flow in its proper relationship with fuel for good

combustion conditions by operating the associated control dampers in the

order of two for each mill.

According to the mill status, high selection logic compares the

secondary air demand signal to a fixed value (i.e. minimum secondary air

flow, cooling air); the highest of them becomes the set point of the secondary

air flow controller in the mill. The air flow control is shown in Figure 3.10

and 3.11.

Figure 3.10 Closed loop control of PA flow

64

Figure 3.11 Secondary air flow control to coal mills

3.15.1 Primary Air (PA) Control to the Coal Mills

The speed of the feeder is sometimes fed back to the master system

as an indication of coal flow, to provide a closed loop operation. It is not a

perfect solution, since a change in the calorific value of the coal cannot be

determined by this system. But in the absence of reliable and fast systems for

measuring the heat input from coal it becomes a challenging task.

Although the system described above provides the necessary

control, it cannot deal with the changes in the Primary Air (PA) flow caused

by the external factors. Therefore, if the PA flow changes, the system must

wait for the resulting change in steam pressure before a correction is made.

65

An approach to overcome this limitation is to provide a closed-loop

control of the primary air flow. The system detects and immediately reacts to

the changes in PA flow, and adjusts the flow control damper to compensate

the disturbances so as to minimize the steam production. Again, a feeder

speed signal, representing fuel flow, is fed back to the master system to

provide closed loop correction for speed changes, which would otherwise

introduce disturbances in the steam pressure.

Both of these systems adjust the feeder speed after the PA flow has

been changed, and this can lead to the delayed response to changes in the

demand. A system that adjusts the speed of the feeder in parallel with the PA

flow is incorporated. This also shows some practical refinements like

minimum limit block that prevents the PA flow from being reduced below a

predetermined limit, and a minimum selector block which prevents the coal

feed being increased above the availability of primary air (the bias unit sets

the margin of air over coal).

3.15.2 Secondary Air Flow Control to Coal Mills

The SA flow set point is compared to the SA of the related mill

plus the evaluated PA flow (temperature compensated) and through a

controller sets the demand for the control of the dampers.

According to the mill status, the “secondary air demand” signal will

be as follows:

no mill in service: the above signal will be equal to zero, it means

only minimum secondary air will be required

related mill in service: the above signal will be the characterized

mill load signal (i.e. mill coal feeders rate)

66

related mill out of service and at least one mill in service

The above signal will be equal to approximately 75% (to be

defined) of the average SA flow to mills in service.

The SA flow demand is actually the average demand for each of the

two dampers. The operator can settle a bias in order to divide the demand

between the two dampers. If one damper is in manual mode and the other

damper in automatic mode then the variation in the mode of operation is

compensated by the damper not participating in the control. Thus, the bias is

continuously calculated when one or more dampers are in manual mode.

When the last damper is put in automatic mode, the bias is released

and is actually between the dampers. The resulting demand to the individual

damper is compared to the damper position (measured by position transmitter)

through a high reset proportional plus integral controller which sets the

controller output for the P/I converter.

Proper firing action is performed according to the request from the

burner management system depending on the air and flue gases in a functional

group that forces the SA control dampers to proper position. They are as

follows

Partially open (approx. X%) to perform mill startup

Partially open (approx. 30%) to guarantee minimum combustion

and air flow rate to perform furnace purge sequence

Last position for five minutes if the combustion air flow is

below the purge rate at the time of the trip including the waiting

time for purge

Fully open for natural draft requirement

67

3.15.3 Secondary and Tertiary Air Flow Control to the Coal Mills

According to the mill status, a high selection logic compares the air

demand signal to a fixed value (i.e. minimum mill air flow, cooling air), the

highest of them, multiplied by the output of the air master control station (i.e.

excess air demand) which becomes the set point of the secondary plus tertiary

air flow controller to the mills.

The SA plus the TA flow set point is compared to the related SA

plus TA flow of the mill (temperature compensated) through a controller that

sets the demand for the control damper. According to the mill status, the

“secondary plus tertiary air demand” signal will be as follows

no mills in service: the above signal will be equal to zero, it

means only minimum air will be required;

the related mill in service: the above signal will be the

characterized boiler load signal (i.e. SH steam flow)

The related mill out of service and at least one mill in service:

the above signal will be equal to approx. 75% (to be defined) of

the average SA plus TA flow to mills in service.

The resulting demand of the individual damper is compared with

the damper position (measured by position transmitter) through a high reset

proportional plus integral controller that sets the control output to the P/I

converter.

Proper firing action are performed according to the request from

burner management system and air and flue gases functional group that force

SA plus TA control damper at proper position, that are as follows

68

partially open (approx. X%) to perform mill start-up

partially open (approx. 30%) to guarantee minimum combustion

air flow rate to perform furnace purge sequence

last position for five minutes if the combustion air flow is below

the purge rate at the time of the trip, waiting time for purge

fully open for natural draft requirement

3.16 MONITORING THE FLUE GAS EMISSIONS USING GAS

ANALYZERS

Conservation of sound environment is an important task. The

present set up consists of a gas analyzer for measuring SOx, NOx, CO and

CO2 emissions which is a ZKJ gas analyzer. The gas samples collected are

converted to an equivalent electrical signal (4-20mA) which is in turn

visualized in the DCS. The major drawback with these gas analyzers are

formation of sulphuric acid when the temperature of the flue gas falls below

160 degree Celsius. This phenomenon is called as cold end corrosion. Hence

this requires extensive day to day maintenance which is a tedious job. This

type of analyzer comes in the category of dual beam type. The overview of

the gas analyzer and its overall arrangement is shown in the Figure 3.12. The

features of the gas analyzer are as follows

Measurement by the infrared ray method (dual beam optics) and

excellent in long-term stability.

Hardly affected by unintended gases because interference

components' influence is corrected with twin detectors.

Standard equipped with automatic zero/span calibrating function.

Space saving design allowing maintenance from the front of

each analyzer.

69

The specifications of the gas analyzer are listed in the Table 3.4.

Table 3.4 Specifications for gas analyzer

S.No Characteristics / criteria/Type Type/Rating

1. Measuring object Exhaust gas of Incinerator and

boiler, etc.

2. Measurable components NOX, SO2, CO and CO2 emissions

3. Measuring system Dual beam type infrared method

4. Measurement range for NOX

emissions

0 to 50

5. Measurement range for SO2

emissions

0 to 50

6. Measurement range for CO

emissions

0 to 50

7. Measurement range for CO2

emissions

0 to 10 % or 0 to 20%

8. Repeatability ±0.5%FS

9. Linearity ±1%FS

10. Zero/span drift ±2%FS/week (O2: ±2%/month)

11. Response time 90% response, from the device inlet

12. Output signal 4 to 20mA DC

13. Contact output Auto calibration status,

maintenance status, concentration

alarm, CO peak count alarm, range

identification of each component

14. Contact input Auto calibration start, range, change

over, pump ON-OFF.

15. Function Auto calibration, average value

calculation, concentration alarm,

CO peak count alarm

16. Display LCD with back light

17. Recorder 6-point recorder mounted

18. Power supply 100V, 110V, 115V, 200V or 230V

AC

19. Outer dimensions 800 W x 1800(H) x 825(D) mm

70

Figure 3.12 Overall arrangement of gas analyzer for measurement of

flue gases

3.16.1 Gas Sampling System

The gas sampling system includes gas extractor for extracting the

sample of flue gases. From here the collected gas sample passes to mist filter

after passing through a drain separator from the inlet valve. The drain

separator helps to filter the dust particles before it passes through the mist

filter. The flue gases at the exhaust should be at a temperature of 150 degrees

Celsius. If this temperature falls below 140 degree Celsius then formation of

mist takes place. Hence the mist can be reduced to a certain extent. The

pressure of the exhaust gases are reduced at pressure drain pot. A three way

solenoid valve regulates the flow of flue gases to the gas aspirator from where

the sample of harmful flue gases are collected and sent to mist catcher which

captures the moisture and further the gas samples are dried in a gas dryer.

From the gas samples the NOx, SOx, CO and CO2 gases are collected in a set

up fitted with pressure regulating solenoid valves. A flow meter with a

membrane filter arrangement is used before the flue gas reaches the infrared

gas analyzers. The Figure 3.13 shows the subsystem for gas sampling.

71

Figure 3.13 Gas sub sampling system

At present the combustion quality and the adjustment of air to fuel

ratio is done based on the experience gained by the control engineer. The

colour of the combustion flames depends on the calorific value of the lignite

(fuel) used for firing. The colour of the flame images in turn indicates the

amount of air to be supplied so as to ensure complete combustion. When

combustion process is incomplete the colour of the furnace flame is blackish

due to the presence of unburnt carbon content. Offline analysis of the flame

images with its corresponding flue gas emissions and combustion quality

using indigenous image processing and intelligent algorithms has motivated

this research work. The information obtained from the colour of the flame

images can be used for online monitoring which can be achieved by

integrating these results with the Distributed Control Systems (DCS) for

optimization of flue gas emissions at the furnace level.

72

3.17 FLAME MONITORING

Monitoring the status of a flame is not easy. The detector must be

able to discriminate between the flame that it is meant to observe and any

other in the vicinity, and between that flame and the hot surfaces within the

furnace. The detector must also be able to provide reliable detection in the

presence of the smoke and steam that may be swirling around the flame. To

add to the problems, the detector will be required to operate in the hot and

dirty environment of the burner front, and it will be subjected to additional

heat radiated from the furnace into which it is looking. The flame scanners of

a boiler are vital to the safety and protection of the plant. If insufficient

attention is paid to their selection, or if they are badly installed or

commissioned, or if their maintenance is neglected, the results can be, at best,

annoying. The problems will include nuisance trips, protracted start up of the

boiler and the creation of hazardous conditions that could have serious safety

implications.

A flame scanner is a complex optoelectronic assembly, and modern

scanners incorporate sophisticated technologies to improve flame recognition

and discrimination as discussed by Wang Huajian et al (2006). Although the

electronics assembly will be designed to operate at a high temperature, unless

great care is taken this value could easily be exceeded and it is therefore

important to take all possible precautions to reduce heat conduction and

radiation onto the electronic components. The illustration shows how a heat

insulating nipple is used to prevent undue heat being conducted from the

boiler structure to the electronics enclosure. It also shows two purge air

connections that are provided between the electronics enclosure and the

swivel mount. Either of these connections may be used, the other being

blanked off. This flame monitoring system determines the presence or

absence of the flame in the combustion chamber.

73

3.17.1 Flame Spectra

The spectrum of radiation from a flame is determined by many

factors, including the type of fuel being burned and the design of the burner.

The intensity of the flame tends to be low for gas and high for coal and oil.

The flame will also flicker and, in general, low NOx burners will demonstrate

a lower flicker frequency than gun type burners. Wang et al (2002) stated that

oil and coal flames tend to produce a higher degree of infrared radiation,

whereas a gas flame is rich in ultraviolet radiation. Radiation in the visible

part of the spectrum will also depend on these factors, but these days the

tendency is to use detectors whose response is biased towards either the

infrared or the ultraviolet end of the spectrum, since emissions in these ranges

provide better indication of a flame than visible radiation, which can be

plentiful and misleading. Each type of fuel also produces byproducts of

combustion, which affect the transparency of the flame and therefore the

blanking effect it has on adjacent flames or on any flames on the opposite side

of the furnace. Deguchil et al (2005) stated that the oil and coal flames tend to

obscure infrared radiation, while gas flames produce water vapour which

obscures ultraviolet radiation.

The manufacturer's advice on the type of flame scanner to use in

various applications varies with respect to the type of the firing system used.

From the look up Table 3.5 it is observed that for corner fired (tangential

system) system with oil for initial firing and coal for continuing the firing

process infrared camera is preferred with cooling arrangement to monitor the

flame status. In certain circumstances a given type of flame scanner will

provide better or worse performance than would appear to be indicated from

the table. Reputable manufacturers will be pleased to provide application

specific guidance. At the design stage this advice will be based on previous

74

experience of similar installations. For a retrofit on an existing plant, the

manufacturer should be asked to carry out a comprehensive site survey, using

various types of scanner, while the burners are started, operated under various

loads, and stopped. Several tests may be required, and a survey may last for

several days.

Table 3.5 Flame scanner application guide

Boiler type Fuel typeDiscrimination capability

Infrared Ultraviolet

Front-fired Gas

Oil

Coal

Gas/oil

Gas/coal

Oil/coal

Coal/oil/gas

M

H

H

M

M

H

M

H

H

H

H

H

H

H

Corner-fired or

tangentially fired

Gas

Oil

Coal

Gas/oil

Gas/coal

Oil/coal

Coal/oil/gas

L

H

H

L

L

H

L

H

H

H

H

H

H

H

Opposed-fired Gas

Oil

Coal

Gas/oil

Gas/coal

Oil/coal

Coal/oil/gas

L

M

M

L

L

L

L

H

M

M

M

M

M

M

H = high, M = medium, L = low

75

3.18 TYPICAL DCS ARRANGEMENT

DCS stands for 'distributed control system' as mentioned earlier.

The term 'distributed' means that several processors are operating together.

This is usually achieved by dedicating tasks to different machines. It does not

necessarily mean that the separate computers are physically located

in different areas of the plant. The typical DCS display is shown in

Figure 3.14(a) and (b). The following notes relate to individual parts of that

system. In practice each manufacturer will usually offer some variant of the

system shown in this diagram and the relevant description should be

consulted, but the comments made here are general ones which may help to

identify the points which should be considered and discussed when a new or

refurbished system is being considered. The central cabinet system houses the

processor which offers the necessary control action as shown in Figure 3.15.

Figure 3.14 (a) DCS display for control in a boiler (courtesy, NLC)

76

Figure 3.14 (b) DCS display for Air Master Control (courtesy, NLC)

The combustion air master control is designed to maintain the air

flow in its proper relationship with fuel for good combustion conditions. A

high selecting logic compares the boiler firing rate demand signal, generated

by unit coordinator logic multiplied by the output signal of O2 controller in

order to weigh the right amount of combustion air, to the total fuel (coal plus

oil) flow signal; the highest of them compared via a high selecting logic, to a

fixed value to provide a minimum combustion air flow capability by

preventing the air flow set point from being reduced below 25% of full range

(25% is minimum air flow as per NFPA code) becomes the set point of the air

master controller; the result is that actual fuels flow sets the minimum air flow

77

demand. The output signal of the air master control station (i.e. combustion

excess air demand) corrects the set point of each secondary plus tertiary air

flow control; if all of them are in manual mode, the air master is forced to

manual too.

The boiler control includes the drum level control, drum pressure,

temperature and furnace flame temperature. Apart from these controls the

control of the coal mills, air master control to the coal mills, oil control for

initial firing, atomizing steam pressure control and excess oxygen control.

The above mentioned controls are also integrated with DCS for online

monitoring. Figure 3.16 shows the typical arrangement of the instrumentation

and electrical systems in a DCS.

Figure 3.15 A Typical DCS configuration

78

Figure 3.16 Typical integration of DCS with instrumentation and

electrical systems

Thus an elaborate overview of the existing set up at NLC for boiler

control, air/fuel ratio control, flue gas emissions control and combustion

control are discussed in this chapter. The technology behind the existing

flame monitoring at NLC, TPS, expansion I and its functionality is also

briefed in this chapter. The overview of the existing set up has enabled to

develop an economical intelligent scheme which can be integrated with the

DCS for the automation of the power plant.