control & instrumentation 2

(Restricted Circulation Only)

CONTROL AND INSTRUMENTATION VOLUME II

Power Management Institute NOIDA

CONTENTS

S.No. Description Page Nos.

1. Automatic Turbine Run Up System 1

2. Turbovisory Instruments 28

3. Furnace Safeguard and Supervisory System 48

4. Role of Analytical Instruments in Thermal Power

Stations 65

5. Automatic Control 99

6. Data Acquisition System (DAS) 155

7. Distributed Digital Control & Monitoring and

Information System 176

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1. Automatic Turbine Run Up System INTRODUCTION To have the higher unit availability and the optimum utilization of the fuel and capacity of the power

generating units, keeping in view the high capital involved, high fuel cost and ever increasing

demand in the grid, it is always been a point to have minimum outage of the power generating units,

reduce the extent of damage in case of faults and the facility to detect the faults and their causes,

facility to have an overview of the system and its performance and the facility for start up and shut

down of the power generating unit in the minimum operating time, it is always desirable to have

proven and reliable system to perform all the above mentioned functions and have high availability

of the system. In view of the above, the turbine is equipped with Automatic Turbine Run Up System

(ATRS), Turbine Supervisory Instruments (TSI), Turbine Stress Evaluator (TSE), Electro Hydraulic

Governing System (EHG) etc.

The ATRS works in conjunction with other turbine related controls like TSE, TSI, EHG etc. to have a

centralized control of turbine and related auxiliaries. The signals, commands and feedback status

of various above mentioned turbine control system are to be acquired, validated and executed so

as to achieve proper operation and control of Turbine Generator Set.

For start up, acquisition and analysis of a wide variety of information pertaining to various

parameters of steam turbine, demand quick decisions and numerous operations from the operating

personnel. In order to reduce the arduous task of monitoring various parameters and effect

sequential start up, minimize the possible human errors and to achieve start up in minimum time in

optimum way Automatic Run Up System (ATRS) is introduced.

For all our previous projects like Singrauli, Korba, Ramagundam, Farakka Stage I & II etc. we have

ATRS implemented in solid state hardware i.e. electronic part of ATRS were realized in printed

circuit borads using transistors, resistors etc. and for operator intervention and observation and

plant control & monitoring, conventional pushbutton, hand/auto stations indicating lights, lamp

indications etc. were being provided on Unit Control Desk (UCD) and Unit Control Panel (UCP).

However for NTPC’s future projects due to the advent of microprocessor based technology and

CRT/KBD based plant control and monitoring philosophy, it has been decided to specify ATRS

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based on state-of-the-art microprocessor technology having CRT/KBD operational features, so as

to have uniform and operating hardware philosophy for plant C&I as well as for turbine C&I.

Accordingly from Farakka Stage-III onwards microprocessor based ATRS with CRT/KBD control

and monitoring facility is being specified for turbine operation and control.

CONTROL AND MONITORING PHILOSOPHY The ATRS is based on functional group philosophy i.e. the main plant is divided into clearly defined

sections called functional groups such as oil system, vacuum system, and turbine system (Fig. 1 &

2). Each functional group is organized and arranged in sub group control (SCG), sub loop control

(SLC) and control interface (CI). Each functional group continues to function automatically all the

time demanding enable criteria based on process requirements and from neighbouring functional

groups if required. In the absence of desired criteria, the system will act in such a manner as to

ensure the safety of the main equipment.

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The task of the ATRS control system is to control, monitor and protect all devices / drives for:

• Start up and shut down sequence performed in a reliable way.

• Protect drives and related auxiliaries.

• Uniform and sequential information to operator about the process.

• Distinct information about the nature and location of faults.

The ATRS is based on functionally decentralized hierarchical structure. Functionally decentralized

means that each and every drive / actuator has its own dedicated set of hardware including

controllers, interface modules etc. The “Hierarchical Structure” refers to the control system divided

into three control levels to achieve higher degree of automation. Each control level has its own

specific task and depends on the subordinate lower control levels. If the higher control level fails,

the next control level is not affected and allows the plant to run safely.

Levels of control available in ATRS are as follows:

The Functional Group Control is the automatic control of a part of the system, this part being mostly

independent (functional group) or of a part process.

These controls obtain:

• Group Controls (GC)

• Sub Group Controls (SGC)

• Sub Loop Controls (SLC)

Group Controls Group Controls contain the operational logic circuits of the underlying

sub group controls. They are designed with logic technique and not

with sequential technique.

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The group control has the task of deciding when, how many and

which of the underlying sub group controls shall be operating or

stopped.

In all cased when a functional group is only composed of one single

sub group, the group control only decides when the functional group

shall be operating or stopped. For a unified concept and a unified

operational technique for all functional group controls the group

control shall also be used for functional groups with one sub group

control only.

Sub Group Controls The sub group controls contain the sequential logic for switching

machines on and off, including all auxiliary equipment (sub groups).

They are preferentially designed in sequential technique, except for

cases when technique and economic reasons permit a renouncement

on the sequential technique. In these cases a pure logic circuit is

used.

Sub Loop Control Sub loop controls are different from other group controls, as they can

be switched on and off manually, but they can only receive directional

control commands (servo HIGHER/LOWER motor ON/OFF, etc.) from

criteria (such as auxiliary oil pump automatic controls, pressure and

level monitoring controls).

SYSTEM OPERATION MODES The following three operating modes are possible under sequence start up modes:

Automatic Mode

In automatic mode the sub group control coordinator is first switched to “Automatic ON”. The

automatic control becomes effective and induces the desired operating status only when a program

has been selected (“Startup or Shutdown”).

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The step is set if the criteria for it are fulfilled and a command is sent to the subordinate control

interface. Preparation are simultaneously made for setting the next step. The program continues in

this manner from step to step. The step which outputs the control and the criteria for the next step

can be displayed in the CRT and control station. Manual interventions are not necessary when the

program runs without faults.

Semi Automatic Mode

The semi automatic mode enables continuation of the program step by step despite the fact that the

step criteria are missing. The presence of all criteria necessary for a step are simulated by manual

operation of a key switch; this enables continuation of the program. This is useful if the program

stops because e.g., fulfilled plant criteria cannot be detected because of a defective transmitter.

Exact knowledge of the process events is a prerequisite for this, however.

Operator Guide Mode The automatic control only processes information criteria form the plant but does not output any

commands. All commands must be input to the control interface level manually. The selected step

sequence now continues with the process independent of the fulfillment of criteria.

CONTROL INTERFACE The control interface module forms the link between the individual commends and the power plant

(Fig. 3). Each remote controlled drive has a control interface module. The module consists of

command section monitoring section, power supply and alarm section. The command section

proves the control commands according to their priority and validity and passes actuation signals to

the interposing relays in the switch gear. Solenoid valves can be actuated directly up to certain

capacity (36 W). The monitoring section normally checks the command functions, the position of

the drive and the check back signals and transmitters to the desk, protection logic and FGC.

The control interface module type AS 11 is used mainly for ON/OFF motor drives. AS 12 for motor

operated regulating valves, and AS 13 for solenoids. The CI modules monitor status discrepancies

running time between command output and check back actuation of the toque switches, check back

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for on coincidence +24 V supply voltage for module, control circuit MCB in the switch gear and

blocking of command by protective logic. Binary signal conditioning of check back contact,

selective fault conditions are also done, protection commands are given priority.

Sub loop control (SLC) is switched ON, it actuates the connected mechanical equipment to the

required operating condition as per the process condition. No sequence logic is involved. SLC can

be switched ON/OFF either manually or through SGC. (Fig. 4)

CONTROLS AND DISPLAYS SGC switching ON/OFF can be done from desk tile (Fig. 5). Displays of step and criteria are

available at the control desk. PB 3 is for switching ON and OFF. The steady glow of lamp 7

indicates auto ON and lamp 6 is for OFF. PB 2 is for startup and 1 for shutdown in auto mode.

Rapid flickering (8 HZ) light in lamp 4 or 5 indicated the programme is running towards desired

status, “steady” on completion of programme and slow flashing light indicates that the programme is

in the desired mode but a process fault has appeared. Operating and fault conditions can be

inferred from Fig. 6. The control tiles of SLC and CI are shown in Fig. 7 & 8. The interpretation of

CI desk tile is shown in Fig. 9.

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OPERATOR INTERFACE DEVICES To interact with the process and to have link between various devices and operator, interface

devices are required. The devices can be indicating type or can be recording type or can be

command issuing type.

The indicating devices are basically used to know the current status of the process or the current

status of the sequence being executed. These devices can be panel mounted indicators, step

criteria displays, status indicating lights, alarm fascia windows etc. With the advent of

microprocessor based control system with CRT/KBD for control and monitoring facilities, the

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indication of the process is displayed on the CRTs and only very limited (critical applications) back

up indicators are provided.

The recording devices are used to keep the records of the parameter variations of the process.

These can be multipoint/multipen recorders, single point recorders, logs (hourly, daily, monthly,

yearly etc.), sequence of event records etc. in the case of CRT/KBD based control systems, most

of these functions are being carried out through dedicated printers etc.

The command issuing type operator interface devices are being used to issue commands to various

devices/drives to on/off as per the process requirement. These devices can be auto-manual

stations, hand-auto stations, setters, P.B. stations etc. for CRT/KBD based control systems most of

these functions are being carried out through KBD. These conventional P.B. stations are only

provided for safe shutdown of the plant in case of an emergency condition.

The CRT for sub group control are built up from the following module:

1. FK 11 Control Coordinator Actuates, monitors & supplies power to its subordinate module

2. FS 11 Step Module

3. FU 11 Step Monitor

4. FZ 11 Time Programming (for monitoring waiting time)

5. FZ 12 Time Evaluation

6. FA 11 Criteria Selection

7. FA 12 Lamp Amplifier (indication)

8. VO 11 Or Gate

9. VU 11 And Gate

10. VA 11 Logic Tuning

11. VD 11 Diode Decoupling

12. VS 11 Memory

13. VZ 11 Analogue Timer

14. VZ 12 Digital Timer

FK 11 actuates, monitors and supplies power to its subordinate module FS 11, FU 11, FZ 11, FA

11/12, and gating modules. It consists essentially of the command memories for manual/auto mode

of operation and for selection of shutdown/startup operations. The commands of FK 11 are passed

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on to FS 11 modules. FK 11 receives check back signals. Status signals and fault alarms are

displayed on the control tile.

FS 11 consists of 3 identical step elements having input logic gates, step storage and output

amplification. When the first step has been set and the criteria for the next step fulfilled, the

programme advances to the next step, and previous step is reset. The signals for step and criteria

induction are given by modules FA 11/12. FU 11 monitors the correct function of the command

outputs of each step sequence. If the command coordinator has transmitted a command to a step

sequence but no signal emerges or more than one signal is present at the command outputs of that

sequence, the voltage supply to the output amplifier is interrupted even before the spurious signals

can be stored in the control interface module. FU 11 modules transmits this to command

coordinator module.

A time programming matrix (FZ 11) presetting times and scanning cycles (FZ 12) time pulse

generator and counter forms the waiting time and monitors running time within the programmed

course of the step sequence. VO11 and VU 11 logic gating modules generates enabling and step

criteria.

SYSTEM DESCRIPTION Automatic turbine run up system consists of three sub group controls viz. Oil Supply System,

Condensate and Evaluation System and Turbine System. These groups in conjunction with electro

hydraulic speed control and turbine stress evaluator achieves the task of synchronizing and block

loading of the machine or orderly shutdown as required.

SGC Oil Supply and Fire Protection System The sub group control for oil system performs its tasks comprising starting relevant oil pumps,

ensuring turning of the turbine during start up and hot rolling to ensure even distribution of heat, this

task is accomplished through jacking oil pumps and shaft turning gear pump and ensuring the

lubricating oil at pre-defined temperature under various circumstances. The programme is

accomplished through a number of steps and seven SLCs. These include controls of turning gear

system, AC/DC lubricating oil pumps, jacking oil pumps, oil temperature controller etc.

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Shut Down Programme

The shut down programme essentially switches OFF all the equipments in the oil system. The shut

down programme would take OFF if the SGC is “ON” and operator presses the button for shut

down programme and the release criterion for shut down programme is available. The release

criterion would be available only if the HP turbine casing has cooled down and the metal

temperature is below 100oC at the top and bottom of the casing. This interlock is necessary as an

inadvertent initiating of shut down programme, could lead to starving of the oil supply to the

bearings as well as depriving the turbine of turning operation.

SGC Condensate and Evaluation System

The sub group control for condensate and evacuation system accomplishes its tasks which

comprise of keeping at least one of the two condensate pumps in operation, evacuating the non-

condensate gases from the system, maintaining the desired level of condenser pressure when

turbine is in operation and breaking the vacuum as and when required by the mechanical process.

The SGC acts directly on condensate pumps, discharge valves, air isolation valves, vacuum

pumps, air ejectors and air ejector bypasses etc.

Shut Down Programme

The shut down programme can also be initiated by the operator provided the following release

criteria are available:

1. The speed of turbine is less than 200 rpm; and

2. LP bypass system has closed.

SGC Turbine

The sub group control turbine, during start up executes the tasks which comprise of Warming up

the turbine, Speed increase, Synchronization and Subsequent block loading. This sub group also

shuts down the turbine which comprises unloading, closure of steam supply to turbine, isolation

from grid and bringing the turbine drains to desired positions. This SGC acts directly on the

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following systems drains, warm up controller, starting device of turbine governing system, speed

and load set print devices of turbine governing system, auto synchronizer etc.

Shut Down Programme

If the operator switches ON SGC and press the manual push button for shut down programme, the

shut down programme would commence. No release criterion is defined for initiating the shut down

programme manually. In other words, the shut down programme can be initiated by the operator as

per the convenience of the power system.

Unloading and Shut Down

During the planned shutdown, prior to beginning of unloading, if possible, the main steam

temperature is to be reduced, in order to keep the metal temperature at a lower value when the

turbine is re-started after short shut down. The load and main steam temperature are not to be

reduced simultaneously. The rate of unloading is governed by the margins shown on turbine stress

evaluator.

The unloading of the set is accomplished with the help of electro-hydraulic governing system. The

generator gets isolated from the grid as a result of the action of low forward power relay.

In the event of emergency, the turbine can be shut down under any load condition, by operating the

automatic trip gear. The turbine can be shut down either by remote tripping via the solenoid valve

or by manual tripping.

However, the shut down programme commences automatically under protection channel if the

“Condition 1 and Condition 3 exist simultaneously” OR “condition 2 and condition 3 exist

simultaneously“. The condition 1 and 2 and 3 are described below:

Condition 1 Emergency stop valve 1 and “OR” interceptor valve 1 AND 2 are closed and

the pressure of the fluid in the governing system is less than 5 Kg/cm2

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Condition 2 HP control valve 1 or 2 not closed “AND” the start up programme is in “AND”

starting device is at a position less than 56%.

Condition 3 Generator breaker of “OFF”.

Auto synchronizer (type-siemens 7 VE 2): This device precisely adjusts the generator voltage and

frequency with the grid voltage and frequency and closing command is given before the phase

coincidence point taking into account circuit breaker closing time.

TURBINE STRESS EVALUATOR

Function

The recent advances in steam turbine design caused power outputs and main steam conditions to

climb steadily higher. This has also involved a higher degree of material utilization and as a result it

has become necessary to pay special attention to the additional thermal stresses which result from

temperature changes. Each time a turbine is started up from the hot or cold condition, each change

in load and each time it is shut down involves free thermal expansion and restricted thermal

expansion which produces the extra stress.

For economic reasons the question most important to the operator is how quickly the turbine can be

started up and loaded without causing damage or premature ageing of the components. Under

certain conditions a rapid application of load may even be necessary in order to safeguard the

turbine. Furthermore, the permissible rate of load change is of importance for the performance of

the turbine generator in the power system.

Whereas temperature differences within the individual turbine components are responsible for

thermal stresses, it is the mean temperature of the components which determines the free thermal

expansion. Free thermal expansion is monitored by the turbine monitoring system.

To prevent damage due to excessive thermal stresses, recommended values for permissible speed

and load changes are quoted by the turbine builder. Naturally, these estimated values cannot be

comprehensive enough to execute all operational changes utilizing the permissible margins for the

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particular turbine to the fullest extent and taking into account the instantaneous thermal condition of

the machine.

An instrument which from the turbine wall temperatures, determines the permissible operational

changes under all operating conditions, also taking into account the recent operating history. The

measuring points are located in the body of the first main steam, combined emergency stop valve

and control valve in the line and the H.P. and I.P. turbine cylinders, the shaft of the H.P. turbine is

partly responsible, and the shaft of the I.P. turbine primarily responsible for the performance

restrictions.

This instrument, the turbine stress evaluator, allows turbines to be driven in an optimum manner,

i.e. effecting changes as rapidly as possible while incurring minimum stresses. It comprises of

three principal parts: a measuring section, electrical computing circuits and a display instrument.

ACQUISITION OF MEASURED VALUES

1. Temperatures The maximum thermal stress in a turbine component can be ascertained from the difference

between two temperatures. These are the temperature Qi at the surface on the steam side and the

mean temperature Qm of the particular component. These temperature values are supplied by the

wall temperature sensors located in those components of the turbine subject to the most thermal

stress.

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Fig. 10

WALL TEMPERATURE SENSOR

1. Lagging

2. Turbine Casing Wall

3. Thermocouple

A wall temperature sensor for monitoring a part of the casing has two measuring points for

acquisition of these two temperatures. The design of the sensor is shown in Fig. 10. It comprises a

screwed sleeve containing a measuring insert. The screwed sleeve is inserted into a through hole

in the wall of the turbine casing and then welded on the outside. It is made of a material having

temperature characteristics similar to those of the casing. This factor, together with the good

thermal contact provided by the thread, ensures that the temperature gradients through the installed

temperature sensor are identical to those in the surrounding wall. The measuring insert can be

replaced if necessary while the machine is running. This type of sensor is used in valve bodies and

in barrel-type high-pressure cylinders.

If the turbine design does not permit the use of the standard wall temperature, e.g. in horizontally-

split H.P. cylinders, individual thermocouples are located in the appropriate positions.

If the thermal stress in a turbine rotor is to be monitored, a surface temperature on the inside of the

casing surrounding the rotor is measured by a single thermocouple at a point where the dynamic

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behaviour of the temperature corresponds to that of the surface temperature of the shaft. In effect it

is taken as a substitute for the temperature of the shaft surface itself. The corresponding mean

shaft temperature is a simulated valve derived from the measured surface temperature.

All thermocouples are of the sheathed iron/constantan type.

Normally, the turbine stress evaluator is fed by five measuring points. The first two are in the body

of the first emergency stop valve in the main steam lime and are known as the “Admission” wall

temperature sensor. The next two, in barrel-type H.P. cylinders, are fitted in the cylindrical section

adjacent to the first drum stage. These two measuring points are in the “HP Turbine” wall

temperature sensor. The last measuring point is in the flange of the I.P. cylinder inner casing

before the first drum stage to represent the surface temperature of the shaft. This is called the “IP

Turbine” wall temperature sensor. The mean shaft temperature is derived mathematically from this

measured value.

Each thermocouple requires a measuring transducer which converts the thermocouple voltage

corresponding to 0 to 550oC into a proportional D.C. current between 0 to 20 mA. The measuring

transducers are also the reference points and are connected to the wall temperature sensors by

means of compensating leads. They contain a buffer amplifier which separates the input and

output circuits electrically.

2. Load

The load of the turboset P act is measured by means of an active load transducer. It is connected

to the generator through current and voltage transformers and delivers a D.C. current between 0

and 20 mA proportional to 0 to 120% of the active load.

3. Speed

The speed value is acquired by an electrical speed measuring system which consists of a digital

speed transmitter, a hall generator and a speed measuring unit. The measuring unit delivers a

voltage proportional to the turbine speed which is used in the stress evaluator to control the speed

scale of the display instrument.

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MEASURED VALUE PROCESSING The processing unit is a hard-wired analogue computer using integrated circuit modules. They are

mounted in a five-tier group frame housed in sheet steel cubicle which also has space for other

equipment. The power supply to the cubicle, the temperature measuring transducers, the active

load transducer, the display instrument and the recorder needs to be a secure 380/220 V three-

phase system.

An illusion of the mode of operational of the computing circuits is given in Fig. The basic concept

divides the evaluating circuits into three channels corresponding to the three measuring locations:

Admission, HP turbine and IP turbine. Each computing channel determines the temperature

difference ∆µ between the surface temperature and the mean temperature. The thermal stress is

proportional to these temperature differences. The calculated temperature differences are

compared against temperature-dependent permissible temperature differences ∆µ permit which are

derived from function generators.

This gives the temperature margins ∆µ and ∆µ. The margins with the subscript “u” refer to

increasing the steam temperature or increasing speed and load, whereas those with the subscript

“I” refer to reducing the temperature or reducing the load.

The smallest values of ∆µ and ∆µ in each case are selected from the computing channels for the

H.P. and I.P. turbines as the valid margins for the whole turboset. When the turbine is running on

load these values are processed further to give load margins. But in the variable-speed range, i.e.

during startup and shutdown, only temperature margins are displayed.

The margins ∆µA supplied by the “Admission” computing channel is a guiding value for the

maximum permissible warming-up rate of the main steam line and emergency stop valves.

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DISPLAY INSTRUMENT (FIG. 11) The display instrument is divided vertically into two separate panels. The left-hand panel is for

start-up to the point when the generator is synchronized with the supply system and the right-hand

panel is for use when the machine is running on load after synchronizing. Which ever panel is in

operation is illuminated.

DISPLAY INSTRUMENT – CHANGING LOAD

FIG. 11 Across the top of these panels are two green illuminated indicating rectangles and one red

rectangle for fault alarm. The green rectangles indicate which computing channel is supplying the

displayed margins at any particular instant. The appropriate rectangle is illuminated and, in the

case of the turbine panel, with additional indication by luminescent diodes above and below the

symbols for the H.P. and I.P. cylinders. The upper diode indicates from which turbine the upward

margin in originating and lower diode the turbine from which the downward margin is originating.

The appropriate diode then shows red.

During start-up, temperature margins and speed are displayed. The speed appears on a moving

circular scale. The margins are indicated on a fixed scale, graduated in K, by two moving,

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transparent screens which also have red sector shaped areas.

When the machine is running on load, the instrument displays the actual load and the load margins.

The load graduations are also on the moving circular scale. The permissible range of load variation

is again indicated by the red sectors of the moving screens.

The positions of the scale and screens are adjusted by motors controlled by the measured values

and computed values.

USE OF THE TURBINE STRESS EVALUATOR Using the measured values of temperature and power output, the turbine stress evaluator

calculates the range within which the operating parameters of the turbine may be varied without

restricting the rate of change. The range is shown by the margins on the display instrument

separately for warming-up, variable-speed and on-load running.

During start-up the left hand panel of the display instrument is illuminated. The measured values

from all thermocouples are processed simultaneously in the computing circuits. The “Admission”

sensor monitors the main steam pipework and the sensors in the H.P. and I.P. cylinders monitor the

turboset. A push button is provided to select for display either the valve body margins or the

controlling margins for the turboset. This allows the minimum margin to be ascertained, e.g. for

warming-up and also allows further operational changes to be matched to the component

experiencing the highest stress at any particular instant. The indicating rectangles show which is

applicable.

If the margin of a computing channel, which at a particular moment is not feeding the display

instrument, should fall to zero i.e. become the controlling factor for operation of the turbine, its

identifying green rectangle will begin to flash. This indicates to the operator that he must change

over to display that computing channel.

If excessive stress in the valve body is indicated, it can only be reduced by lowering the main steam

temperature or main steam flow rate. This is applicable to the variable speed and load modes.

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If one of the turbine sensors is providing the limiting parameter the stresses in the can be reduced

by appropriately varying the lift of the control valves or by an appropriately timed change in the main

steam temperature and/or reheat temperature.

For example, if during start-up the top screen for the “H.P. Turbine” computing channel reaches the

value OK, it means that the permissible limit of material stress has been reached and will be

exceeded if the control valves are opened further. In this situation appropriate control action must

be taken to produce a delay until a temperature margin is again indicated. Should however, the

bright red sector of the screen have already covered the OK value, the lift of the control valves must

be reduced immediately. If the OK value has already been covered by the dark red area of the

screen it means that the existing thermal stress is already causing serious deterioration of the

material.

When starting up a hot turbine it may be noted that the lower and not the upper screen indicates the

smallest margin. This means that the turbine is being cooled down because, for example, the main

steam temperature is too low and hence the temperature of the inlet steam to the first drum stage is

lower than the casing temperature. In a hot turbine the main steam temperature and reheat steam

temperature should be 50 to 80oC about the mean wall temperature. However, if the temperature of

the emergency stop valve is lower than the mean wall temperature of the I.P. Turbine, the main

steam temperature must first be matched to the temperature of the emergency stop valve. Again it

should be approximately 80 to 100oC above the mean wall temperature of the emergency stop

valve. The main steam temperature or reheat steam temperature should then be increased

according to the value indicated by the turbine stress evaluator so that opening the control valves

does not produce any excessive cooling of the turbine. The upper limit is naturally the rated value

of steam temperature.

Before synchronizing is carried out, it is advisable to have a temperature margin of approximately

20oC available so that a minimum load on the set can be assumed immediately after synchronizing.

When on-load running begins, the stress evaluator display instrument changes over to the load

range and the right hand panel of the instrument is illuminated. In the load range the “HP Turbine”

and “IP Turbine” wall temperature sensors provide the values for calculating the load margins.

However, it is possible to switch back to the variable-speed range in order to check the

instantaneous temperature margins at the valve body or turbine.

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The load on the machine is indicated on the load scale and the positions of the screens delineate

the range within which the load on the turbine may be varied as rapidly as desired without incurring

excessive thermal stress. The rate of load change must always be such that the screens never

cover the indicated actual value of load.

If, as shown in the illustration of the display instrument Fig. 11 the load is 350 MW and the edge of

the upper screen is on the 400 MW mark on the scale, it means that the load can be varied

between 350 and 400 MW without overstressing the turbine. Hence, there is a spinning reserve of

50 MW.

Should the indicated value of actual load be covered by the upper or lower screen during normal

operation, immediate steps must be taken to drive the turbine out of that particular load range. If

the amount of screen overlap is such that the dark red section has reached the indicated value, the

stressing is already of sufficient magnitude to cause serious deterioration of the material.

It is permissible to operate the emergency trip or to reduce the machine load rapidly to the station

service load from any load condition even when it is not directly indicated by the instrument.

The prevailing load margins can be varied within certain limits by appropriate variation of the main

steam temperature or reheat steam temperature. Thus, a reduction of the steam temperature will

produce a large upper load margin and a smaller lower margin, whereas an increase in steam

temperature will produce a smaller upper load margin and a larger lower margin. Any change in

steam temperature at the turbine admission, directly affects the temperature at the first drum stages

of .the H.P and I.P turbines. Even at constant load it results in a change of position of the screens.

Hence, the turbine stress evaluator can monitor permissible changes in main steam temperature

and reheat steam temperature. By changing over to the temperature scale it is possible to obtain

from the displayed margins an indication of the permissible changes in steam temperature.

Recording

The recorder records all measured and calculated temperature, the calculated temperature margins

and the main steam temperature, reheat steam temperature and speed or load in order to permit

monitoring of the turbine operation. It is arranged for the recording of the temperatures to be

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continued even when the turbine stress evaluator is switched off or is defective in order that the

turbine may be driven according to recommended guide values.

Coordination with other Devices

It is logical to arrange for the turbine stress evaluator to act directly on the turbine control system.

The temperature margins determined by the evaluator then determine the rate of change of speed

and load. This is quite easy to effect by means of set point controllers if the turbine is equipped with

an electro hydraulic governor and set point controllers are considered to be fundamental parts of

any good turbine automatic control system and superimposed automatic unit coordinating control.

Summary of the various versions of Turbine Stress Evaluator

1. 2-channel turbine stress evaluator (A/T)

In the case of saturated steam turbines the "IP Turbine” computing channel is eliminated so the 2-

channel version can be used. The display instrument then has also two indicating rectangles

"Admission" (A) and "Turbine" (T) without light emitting diodes. This version is also used for

superheated steam turbines with no reheater.

2. 3-channel turbine stress evaluator (A/2T), Fig. 12

This version is the standard one which has been described in detail and has one computing

channel for the admission (A) and two computing channels for the turbine (2T).

It is mainly used with single-reheat condensing turbines with a main stop valve and bypass valve in

the main steam line and an H.P. bypass branching from between the boiler outlet and the valve.

© PMI, NTPC 26

BASIC SYSTEM DIAGRAM, 3-CHANNEL FIG. 12

LATEST TREND IN TURBINE STRESS EVALUATORS

With the advent of state-of-the-art microprocessor based technology having CRT/KBD control and

monitoring facilities, the TSE has also got a face change. The improved version of TSE now

available is known as Turbine Stress Control System (TSCS). This TSCS works in conjunction with

ATRS and EHG to achieve all the functional requirements.

This new TSCS not only performs the general functions of TSE like computation and display of

stress margins available, continuous on-line monitoring of thermal stress levels, limits of speed and

load changes allowable, but also carry out the fatigue analysis and provide at least three modes of

turbine operation i.e. slow, normal and fast. That is to say, depending upon the urgency of unit start

up, the operator shall be able to select any of the three modes of turbine run-up and loading.

© PMI, NTPC 27

The TSCS has its own dedicated CRT/KBD and one suitable conventional display instrument for

indication to operator. The stress margin and speed/load gradient displays changes colour so as to

attract the operator’s attention whenever the permissible limits are reached/exceeded.

ADDITIONAL ADVANTAGES OF TSCS

1. Computation of residual life of Turbine.

2. Three rates of Turbine run up and loading.

© PMI, NTPC 28

2. Turbovisory Instruments

Though nearly 120 measurements are required for the complete monitoring of the turbine the

following instruments are found to be adequate to provide the necessary information under normal

operating conditions. Therefore the discussion here will centre around the following few and most

important turbovisory measurements. The locations of these instruments are marked in the drawing

No. 13.

TURBINE SUPERVISORY INSTRUMENTATION

i. Shaft Eccentricity

ii. Vibration

iii. Axial shift/Thrust position of rotor

iv. Differential expansion

v. Casing overall expansion

© PMI, NTPC 29

vi. Speed

vii. Control valve servomotor position

viii. Seed gear position

ix. Seal interference

x. Turbine metal/steam temperature differentials

xi. Load limiting gear position

ECCENTRICITY

Eccentricity is the very important parameters to monitor the conditions of turbine. Every machine, is

built up with certain amount of eccentricity on account of the deficiency in machining, sag due to its

weight and the clearance at the bearings. This eccentricity level starts increasing temporarily during

its starting, normal running and shut down periods due to m

i. Temperature causes

ii. Other mechanical causes

TEMPERATURE CAUSES

a. If non-uniform heating and cooling of turbine rotor during turbine start-up, load changes and

casting down period take place, there is a possibility of the eccentricity level going high

temporarily.

b. Possibility of the temperature gradient in its transverse direction in the gland seals is there

when the steam leakages are uneven or the seal steam temperature is abnormal. This

uneven temperature gradient increases the eccentricity level temporarily.

© PMI, NTPC 30

c. Uneven cooling due to improper lagging or water splashes causes the eccentricity to

increase.

MECHANICAL CAUSES

Mechanical causes such as rubbing, faulty couplings, wearing of bearings etc. also increases the

eccentricity level.

All the above causes increase the eccentricity level, though temporarily, they get settled to a

permanent eccentricity if corrective measures are not taken in time and the machines continued to

run with the increased eccentricity level.

Eccentricity is measured in microns or millimeters.

It is measured as a deviation of the mass centre from the geometrical centre of the bearing journal.

This is simply proportional to the maximum rotor deflection occurring at the middle of shaft. The

rotor deflection shifts the centre of gravity of the rotor thus creating an unbalance in the rotating

mass which in turn generates excessive vibrations when the machine is running at normal speeds.

Thus eccentricity measurements provide information on the onset of vibration even when the

machine is at bearing gear speed or at low speeds.

ECCENTRICITY MEASURING SYSTEM PROVIDES

a. Remote digital /Analogue indication of the eccentricity level.

b. Continuous recording of the eccentricity level.

TYPE OF MEASUREMENT

The eccentricity is electrically measured by measuring the variation of an a.c. current in a coil due

to the variation in the proximity of the target material. There are two methods being used worldwide

to measure the eccentricity.

© PMI, NTPC 31

i. Inductive transducer operating at excitation frequencies 50 KHz to 20 kHz.

ii. Proximity (Eddy current) transducer operating at excitation frequencies 500 KHz to MHz.

The transducers of both these types are so mounted as to measure the varying air gap of a collar

specially machined on the rotor. The variation in the gap, as the collar rotates, provides the data of

the peak to peak excursion of the rotor.

MEASUREMENT BY INDUCTIVE TRANSDUCERS

One typical measuring system is shown in Fig.14. The measuring detector of this system consists

of one active and one passive magnetically separate reluctance type transducers both mounted

inside the turbine casing to prevent any error due to environmental changes. The two elements are

connected in an initially unbalanced bridge configuration which is excited by 10 V r.m.s. 1953 HZ

supply.

MEASUREMENT PRINCIPLE OF SHAFT ECCENTRICITY = MARK I

Fig. 14

© PMI, NTPC 32

The measuring unit comprises of a demo-dulator, low pass active filter, amplifier and amplitude

detector cum DC suppressor.

In case of an eccentricity, the bridge output is modulated by a percentage proportional to the

amount of eccentricity with a modulating frequency proportional to rotor speed. The bridge output is

demodulated and then filtered in a fourth order active filter to obtain the modulating signal. This i3

further amplified and fed to the special amplitude detector with built in electronic gate and gate

timers which avoids any change in indication due to sudden change in absolute rotor position or its

speed. The design envisages the detection of positive and negative peaks of the modulating signal

and its difference. This processed signal is then fed to the digital analogue panel meter. The

parameter is also continuously recorded in a single channel recorder. A separate analogue current

output of 4-20 mm is some times provided for datalogger circuit if required.

The unique design of the detector allows a wide mounting tolerance in the air gap setting. The

range of measurement is normally 0 to 500 microns.

Similar measuring procedures are followed by other manufacturers also only with the differences of

excitation frequency and signal processing electronic system.

MEASUREMENT BY PROXIMITY TRANSDUCERS

The transducer is a flat coil of wire, located on the end of a ceramic tip. The coil is protected by

epoxy fibre glass. The ceramic tip extents out from the steel body of the probe. The probe is driven

by a radio frequency voltage generated by a driver unit called proximitor. The prob coil radiates this

signal into the surrounding area as field. if there is no conductive material to intercept the magnetic

field there is no loss of R.F. signal. When a conductive material approaches the probe tip, eddy

currents are generated on the surface of the material and power is absorbed. This loss of power is

proportional to the gap nearer the conductive material comes, more the loss and vice versa. The

proximeter senses this loss and generates a DC voltage enveloped by the peak to peak eccentricity

waves.

© PMI, NTPC 33

VIBRATION

Vibration is the other vital parameter to be monitored in a turbine. Vibration is the back and forth

motion of the machine or machine parts under the influences of oscillatory forces caused by

dynamically unbalanced masses in the rotating system. Vibration can be the cause of trouble, the

result of trouble, the symptom of trouble or a combination of all the three. Like eccentricity, there will

be a certain level of vibration in any machine, how perfectly it might have been built up. This original

level of vibration depends upon the net unbalance left in the machine during the manufacturing and

erection stages. But this initial vibration level increases in due course of operation of the machine

on account of

i. Fast out of balance changes like fracture etc.

ii. Slow out of balance changes like corrosion, erosion, deposits, bends, etc.

iii. Self excited shaft, vibrations like steam pulsations, oil pulsation, etc.

iv. Mechanical looseness in pedestal faults in coupling, bearing etc.

Excessive vibration may lead to mechanical failure of the turbine components and calls for

extremely reliable monitoring system. Vibration originates from the rotating mass centre and is

transmitted radially and axially to the supports i.e. bearing pedestals called radial and axial

vibration.

Thus bearing pedestals are the points where normally the vibration measurements are made.

Generally vertical and horizontal vibrations are measured as these are the radial vibration at 900 to

other.

Vibration is usually measured as the amplitude of the maximum exercise of the vibrating point in

microns. It is either given as the single amplitude (peak) or double amplitude (peak to peak).

The other way of measuring vibration is by measuring the velocity of the motion of the vibrating

point. This measurement is being considered very useful as compared to that of amplitude,

© PMI, NTPC 34

because this is a measure of fatigue whereas the displacement gives only the "Stress". It is

measured in mm/sec. (R.M.S.).

Sometimes a third mode i.e. the acceleration of the motion of the point adopted. The acceleration

measures the amount of vibrating "Force".

The vibration measuring system provides

a. Remote digital/analogue indication of the vibration level.

b. Continuous recording of the parameter senses by different detectors.

c. Annunciation in case of excessive vibrations beyond the safe limit.

THE MEASURING SYSTEM

There are two fundamentally different techniques for this measurement:

i. By velocity transducers

ii. By accelerometers

VELOCITY TRANSDUCERS

There are number of types available. All types basically comprise of a Siesmic mess which as a

result of the vibration, allows a magnet to move relative to a coil in which is generated an e.m.f.

Either the magnet or the coil may be fixed to the vibrating body.

© PMI, NTPC 35

VIBRATION DETECTOR

FIG. 15

The detector consists of two permanent magnets rigidly fixed to the casing with coils arranged as

siesmic mass as shown in Fig.15. The two magnets coil assemblies are arranged to sense vibration

in two mutually perpendicular directions. The measurement system is designed to operate

satisfactorily over a vibration frequency range of 10 HZ to 150 HZ with an acceleration not above

6g.

The measuring unit comprises of preamplifier, integrator, special amplifier, rectifier, Fig.16 gives the

scheme of the measuring system.

© PMI, NTPC 36

The transformation of mechanical vibrations into electrical signal is made in a siesmic sensor which

works according to the electro dynamic method applying the plunger coil principle. A voltage is

induced in the coil due to relative movement between the plunger coil and the magnet which is

proportional to the vibrational velocity. This sort of vibration sensors are called "Velocity Pick Ups".

The induced voltage is preamplified, integrated to obtain the amplitude of vibration and further

amplified in special amplifier. 7t is then rectified and the parameter is displayed on digital/analogue

panel meter. The parameter is also recorded in the multi point recorder. A separate analogue

current output of 4-20 mA can be made available in each channel for datalogger hook-up, if

required.

ACCELEROMETER

Accelerometers, specially based upon the piezo electrical crystal, which generates an e.m.f. when

subjected to stress, are gaining much importance now-a-days because of its simplicity, lightness

and more sensitivity. An electric signal is obtained between the opposite faces of a piezo electric

© PMI, NTPC 37

crystal subjected to mechanical vibration, proportional to the acceleration of the vibration. The

construction details of an accelerometer is shown. in Fig.17.

The piezo electric element, usually an artificially polarized ferroelectric ceramic is arranged so that

when the assembly is vibrated the mass applies a force to the piezo electric element which is

proportional to the vibratory acceleration. This can be found from the law, force = mas x

acceleration.

Accelerometers will be giving vibration in all the three modes namely - Acceleration, velocity and

Displacement.

AXIAL SHIFT OF ROTOR

The thrust bearing is the anchor point of the rotor with the stator in the axial direction. The axial

thrust is the result of the impact of the steam on either side of the blades in each stage. Though

attempts had been made to balance and nullify the thrust by reversing the direction of steam flow in

H.P. and I.P. cylinders and providing double flow L.P. cylinder, there exists, however, a net thrust in

the direction of generator called working thrust.

© PMI, NTPC 38

In order to take the thrust, thrust bearing is provided at the front end of the H.P. Cylinder where

steam enters. The axial thrust may increase on either direction on the following conditions.

ii. More/less resistance developed in the steam flow path on account of salt deposits/erosion,

wearing off etc.

ii. Thrust bearing failure.

iii. Oil flow failure/improper to thrust bearing.

Due to axial thrust, the thrust collar is either on the working pads or on the surge pads depending

on the direction of axial thrust. The measurement System indicates the position of the thrust collar

with respect to the working pads. The indication determines the extent of wear of thrust pads. It. is

imperative to continuously monitor the position of thrust collar as axial shift beyond permissible

limits could lead to mechanical interference and severe rubbing. This service provides:

a. Protection of turbine in case of excessive axial rotor shift towards the generator or towards

the front caused by wearing out of thrust bearing pads.

b. Remote digital /analogue indication and annunciation of the rotor position in the thrust

bearing when the operating conditions are changing.

c. Continuous recording of the rotor position in the thrust bearing.

The detector used presently is a two element variable reluctance type transducer connected in a

bridge configuration which is excited by highly stabilised 10 V. r.m.s. 1953 HZ supply.

The measuring unit: consists of amplifier, active rectifier, liner-ariser, amplifier, a comparators for

annunciation.

The axial shift in the rotor alters the bridge output which is amplified and fed to the line arising

circuits after rectification. The line-arising circuits linearises the inherent non-linearity of the

reluctance type transducers to enable inter changeability of the detectors and repeatability of

measurements. This further facilities reasonable tolerance in mechanical mounting of the directors.

© PMI, NTPC 39

The linearised output is amplified and then fed, to the recorder, the annunciation circuits through

present comparators and analogue to digital converters for display. A separate 4-20 mA analogue

current output can also be provided for hooking up date logger circuit.

The design of this service prevents any spurious tripping-signal due to failure of excitation or power

supply as long as the actual axial shift is not high enough for tripping. The range of measurement is

from (-2) to (1.5) mm of axial shift. The '0' reference position of the rotor is that position when the

collar touches the working pads. The positive axial shift as per convention is the movement of the

collar i.e. the rotor in the direction of the generator and the negative axial shaft occurs when the

collar moves on the front pedestal direction. Usually the working value under normal condition will

be from 0 to -.5 mm beyond which on either direction, the collar will start rubbing the respective

pads.

Measure of the oil pressure on both sides of thrust collar will also give a relative position of the

rotor. Measurement of *temperatures of thrust pads on both sides gives the position of the shaft.

DIFFERENTIAL EXPANSION OF ROTOR AND CYLINDER

The rotating and stationary- part of the turbine undergo different rates of expansion under various

conditions of operation. This is -mainly due to inherent difference in the thermal inertia between

rotating and .stationary parts. Therefore, any shaft, temperature fluctuation would result in different

magnitudes -of expansion /contraction. The difference of axial expansion between the rotor and the

casing is termed as differential expansion. A standard convention is followed that if the shaft

expands more than the casing it is said to be a positive expansion.

On the other hand if the casing contracts or expands more than the shaft it is said to be negative

expansion. A high positive expansion is foreseen under

i. Start up conditions.

ii. After extended period of no load/low load and running followed by sudden loading.

iii. When the exhaust temperature is too high.

© PMI, NTPC 40

iv. Restraint of casing sliding/expansion.

A high negative expansion occurs:

i. During cooling down/shut down

ii. After extended period of full load running followed by low load running.

iii. When exhaust hood temperature is too low.

The turbine supervisory instrument system monitors the differential expansion at any instant and

initiates alarm if the parameter exceeds its permissible limits. This facilitates the operator to take

corrective actions.

This service provides:

a. Remote digital/analogue indication of the differential expansion of HPT, IPT and LPT.

b. Continuous recording of the above parameters.

c. Annunciation in case of imperishable values.

The detector is also a two element variable reluctance type transducer connected in a bridge

configuration which is excited by the common 1953 HZ excitation.

The measuring unit consists of amplifier, active rectifier, linearising circuit, amplifier, and

comparator for annunciation. The measurement principle is the same as in the case of axial shift.

Limiting Values

The range of measurement of HPT is -2 to +5mm.

The range of measurement of IPT is (-3.5) to (+4) mm.

The range of measurement of LPT is (-3.50) to (+5.5) mm.

© PMI, NTPC 41

The above figures are for a specific 210. MW-machine presently being manufactured in this

country. The normal figure for any machine is that there is 2/3 clearance for expansion as

compared to 1/3 for contraction.

CASING EXPANSION /OVERALL THERMAL EXPANSION

The turbine casing is anchored near the middle of LP casing and is free to expand axially on either

directions from the anchor point. Expansion measured at front pedestal is the cumulative expansion

of the casing from the anchor point and thus indicates the degree of thermal socking of casings.

Expansion is also measured at the middle bearing pedestal. Abnormal expansion indicates serious

fault in the machine. Lesser expansion indicates jamming of pedestal on the pedestal mounting

stool or lack of freedom of movement of the steam chest. Higher expansion points out permanent

creep of the machine or material failure. This service provides

a. Remote digital /analogue indication.

b. Continuous recording of the parameter.

MEASURING SYSTEM

Two types of measuring principles are in use:

i By L.V.D.T. transmitters.

ii. By rectilinear potentiometers.

L.V.D.T. TRANSMITTERS

The principle used to detect the overall expansion or the casing displacement is the movement of a

core within a linear differential transformer.

A constant 10kc/s sine wave current is supplied to the primary winding of a linear differential

transformers. The secondary consists of two windings connected in series opposition so that the

input to the amplifier is the difference between the voltage included in each winding.

© PMI, NTPC 42

With no pedestal displacement the core is fully extend from the transformer so that the voltage in

winding A1 balances that of winding A2 to give a zero input to the amplified and hence result in a

zero output on the recorder. As the pedestal expands causing a displacement between the pedestal

and pedestal mounting stool, the core is inserted into the transformer. This causes an imbalance

between the two secondary voltages and this difference is amplified, rectified and smoothened and

fed to the indicating instrument.

RECTILINEAR POTENTIOMETER

In this type the linear motion of the casing is converted to the rotary motion through a suitable rack

and pinion arrangement. The rotary motion is given to the driving shaft of the rectilinear

potentiometer of very accurate electromechanical construction. The potentiometer is connected to

measuring circuit which is energised from a constant d.c. current so that a signal proportional to the

position of the slider is obtainable. As the position of the potentiometer slider is itself dependent on

the degree of overall expansion of the turbine the required electrical output is realised and the value

indicated in indicator/recorder and data-logger. The range of measurement is 0 to 50 mm.

TURBINE SPEED

Monitoring of turbine speed is necessitated especially during start-up till the TG set is synchronised.

The speed measurement system provided in the turbine supervisory instrumentation perform a dual

function of measuring the turbine speed and actuating an alarm signal in case of overspeed. The

indicators provide:

i. Remote indication when the rotor is rotated by the barring gear.

ii. Remote as well as local digital indication of the turbine speed.

iii. Alarm signals at 10 and 16 per cent over speed.

MEASURING SYSTEM

The speed detector consists of slotted disc with 60 radial slots distributed around its periphery and

magnetic probe mounted facing the slots. Rotation of the disc generates voltage pulses in the

search coil. The output is fed to the speed measuring unit, local as well as remote.

© PMI, NTPC 43

The measuring unit consists of a zero crossing detector, a pulse shaper, and an electronic counter

with latch, decoder and display. The spare output for "data logger" is provided by a standard digital

to analogue convertor having an output of 4 - 20mA. The annunciation at 10 and 16 per cent over

speed are provided for recording till synchronisation. At barring speed, the speed display is blanked

and indication is through an indicator lamp.

The voltage from the detector proportional to turbine speed are preamplified and transmitted to the

measuring module in which it is fed to the zero crossing detector and pulse shape. The output of

the pulse shaper is a train of pulses of definite amplitude and width, the frequency of which is

proportional to the speed of the rotor. The train of pulses is then, by a differential cum negative

suppresser, converted to a train of very narrow spikes of width of the order of nanoseconds to avoid

any counting error. The number of spikes are counted with a sampling time of one second,

decoded and displayed. The display of the counted value is through a series of latches to avoid

continuous blinking of all the digits. The range of measurement is from 20-4000 r.p.m. with a

resolution of 1 r.p.m. This provides high speed annunciation only. The actual overspeed "Trip" is

through Hydro-mechanical governing only.

Another type of speed measurement used in older units is by means of a permanent magnet techo-

generator coupled to the main shaft of the turbine through gears of speed ratio 1:1. Thus the output

voltage of this techo-generator is proportional to the speed of the turbine. This voltage is rectified

and measured by a DC voltmeter calibrated in terms of speed.

A third method is now being widely used by the .advanced countries and may find its place in our

country also-shortly for speed measurement. This method employs an eddy current pick up facing a

notch or a projection on the main shaft. The pick up generates a pulse when the notch/projection

passes it. Count of these gives the speed of the machine.

CONTROL VALVE SERVOMOTOR POSITION

On- synchronization the speed of the turbine rotor remains more or less unaltered and the change

in load is reflected through the variation in control valve servomotor position. It is, therefore,

imperative to monitor the control valve servomotor position continuously after synchronisation. This

service provides:

© PMI, NTPC 44

a. Remote digital indication.

b. Continuous recording of the parameter after synchronisation.

The detector consists of a wire wound potentiometer in a metal case. The slider shaft is supported

by a ball bearing and is coupled with the servomotor stem through mechanical linkage and gear

train.

The principle of measurement is similar to the casing expansion service as described above. The

display is on digital panel meters and the recording on a single channel recorder. A separate 4-20

mA analogue signal also can be made available for data logging purposes. The measurement

range is 0 - 300 mm.

SPEEDER GEAR POSITION

The speeder gear position is continuously monitored to facilitate the operator to keep a watch on

the opening condition of the valves. This service provides:

a. Remote digital indication.

b. Initiation of taro logic input for switching of the speeder gear motor at extreme position to

avoid over travelling.

The detector is similar to that of the control valve servomotor position and is coupled with the

load/speed control pilot spool through a gear train.

The principle of measurement is similar to the casing expansion as described. The display is a

digital panel meters and the recording of the parameter is not necessary. A separate analogue

current output of 4 - 20 mA is envisaged for data logger hook up.

The speeder gear has been provided with a free clutching mechanism which prevents the damage

due to over travel of the speeder gear. However, as a backup protection two switching circuits have

been designed to sense the zero and maximum position of the speeder gear position which

switches of the speeder gear meter in these extreme positions.

© PMI, NTPC 45

SEAL INTERFERENCE

During the start-up and coasting down, gland seal rubbing may occur in the event of high differential

expansion contraction and bowing of rotor.

Consequently monitoring of rubbing of gland seals is considered necessary during this period. This

service provides:

a. Remote audio alarm through a common speaker and also a head phone.

The detector comprises of an electric-dynamic micro-phone with built in pre-amplifier and filter.

The measurement unit comprises of an audio amplifier, a speaker and a head phone with a jack-in-

plug, selector switch.

In case of a gland seal rub, a high frequency noise from direct metal to metal contact is produced

which is sensed by the detector. This signal is pre-amplified and through a high pass filter fed to the

measuring unit. It is amplified in the audio amplifier and fed to the speaker. Each channel is

selected through the selector switch to identify the exact faulty gland seal.

TURBINE METAL AND STEAM TEMPERATURE

Metal temperature of the turbine is the most essential parameter to be monitored since it directly

reflects the amount of stress on tile various components.

This service provides:

a. Continuous recording of absolute metal and steam temperature.

b. Continuous recording of differential metal temperature.

c. Audio visual annunciation in the event of impermissible differential metal temperature.

© PMI, NTPC 46

The detector comprises of duplex type chromel alumel thermocouple with stainless steel thermowell

fixed at different locations of the turbine body.

The absolute metal temperature and steam temperature are also recorded on dot type recorders.

The differential metal temperature is processed in separate differential amplifiers and fed to dot type

recorder which is directly calibrated in terms of temperature differential.

In case of impermissible differential temperature provision exists for audio visual alarm both in

positive and negative directions.

LOAD LIMITING GEAR POSITION

Monitoring of load limiting gear position is necessitated to ascertain the optimum allowable loading

on the turbine. This service provides:

a: Remote Digital Indication

The detector comprises a rotary potentiometer similar to that of speeder gear service.

The principle of measurement is similar to that of casing expansion service. The display is

on digital panel meters. A separate 4 - 20 mA current output can be provided for data logger

hook-up.

PROTECTIONS

The turbine supervisory instrument system includes the turbine protection and associated logic e.g.

low lube oil pressure protection, low, vacuum protection, high axial shift protection etc. Control for

electro hydraulic transducer, control for speeder gear etc.

GENERAL CONSIDERATION

Keeping in view the important role of turbine supervisory instrumentation, every conceivable effort is

© PMI, NTPC 47

made to ensure the quality of measurement modules /circuits. The present day practice is that the

circuit design uses semi-conductors and most of them are integrated circuits for their obvious

advantages. The component layouts follow the recent trends in electronic industries and are

assembled in draw out type plug in modules with printed circuit board inserts. A highly stabilized

crystal oscillator circuit is normally provided for excitation of measuring circuits to prevent any error

due to supply variations. Separate channels are provided for different services. Necessary field

check facilities are incorporated to check the complete measuring system even while the turbine is

on load. The various operating and adjusting controls are provided on the face plates of individual

modules. This modular concept allows easy access to the circuit boards for test calibration,

adjustment or replacement and this ensures maximum flexibility in servicing and maintenance.

All the detectors are of compact and rugged construction and are epoxy coated for hermetic sealing

and preventing damage due to vibration etc. The detectors are subjected to rigorous environmental

tests, like dry heat, damp heat etc. for absolute reliability.

© PMI, NTPC 48

3. Furnace Safeguard and Supervisory System

FSSS means Furnace Safeguard & Supervisory System, the system which is used in almost all

types of boiler. The system has been designed to offer maximum protection, minimum nuisance

trips, minimum power consumption and maximum life of the components used. It is designed to

ensure the execution of a safe, orderly operating sequence in the start-up and shut-down of fuel

firing equipments in a boiler and to prevent errors which may be committed by an operator due to

ignorance. The system is a complex one and has got multiple steps which cannot be left at the

discretion of operators to follow it in a sequential manner. Adequacy of ignition energy is a crucial

part in a boiler before cutting in any fuel input into the furnace. Because it is possible that unburnt

particles must have got accumulated inside the furnace and sudden ignition of it may lead to major

explosions in a boiler.

In our earlier projects, FSSS was implemented in relay based/solid state hardware. From

Ramagundam stage II (3 x 500 MW units) onwards, FSSS is being implemented in microprocessor

based hardware. In all these projects, control was achieved through PB stations mounted in the

control Desk. However in all our new projects like Farakka Stage III (1 x 500 MW), VSTPP stage II

(2 x 500 MW) FSSS shall be implemented in state of the art microprocessor based systems with

CRT/KBD operation.

In a 210 MW BHEL boiler there are 13 elevations around the furnace through which fuel and air are

admitted into the furnace for combustion.

In the Fig.18 there are 13 elevations of air compartments for each corner and i.e. 13x4=52 nos.

totally, 6 elevations of coal compartments i.e. A, B, C, D, E, & F, in all the 4 corners and three

elevations of oil guns i.e. 3x4=12 nos. guns & 4 elevations of auxiliary air dampers i.e. 4x4 = 16

Nos.

© PMI, NTPC 49

Adjacent to the oil guns there are HEA ignitors. There are flame scanners also in each oil

compartment which senses the flame of individual gun. There are fire ball scanners also which

sense the fire ball formed in the centre of the furnace.

Besides above there are other field equipments also which are as follows:

1) LOW (Light oil trip valve). It depends whether light oil firing provision is there or not. Now-a-

days heavy oil is fired directly by high energy arc ignitors.

2) HOW (Heavy oil trip valve)

3) Hydromotor/trip valves. These are for oil, air and steam. If light oil is not fired air trip valve is

not there.

4) Steam control valve

© PMI, NTPC 50

5) Secondary air dampers

6) Gun maintenance switches

7) Hot air gate

8) Cold air gate

9) Hot air dampers

10) Cold air dampers

11) Feeder speed control

12) Gun advance/retract mechanism

13) Ignitor advance/retract mechanism

14) Pulverisor discharge valves

15) Heavy oil recirculation valve

16) Other field temperature, pressure switches/sensors are there to give feed back to the control

room.

© PMI, NTPC 52

Before boiler is lighted up furnace purging is done for which following interlocks should be satisfied

see Fig. 20. Furnace purging is done to remove all unbrunt particles which may have been inside

the furnace during earlier unit operation.

1) Loss of AC is not there i.e. 110VAC/220VAC.

2) Loss of 220VDC is not there.

3) Both drum level V. high condition is not there from Hydra step instrument.

4) Both drum level V. low condition is not there from Hydra step instrument.

5) One set of ID/FD fans should be in service.

6) No P.A. fan should be in service.

7) Air flow should be more than 30%.

8) Auxiliary air dampers should be in modulating condition.

9) WB/Furnace ∆ P should be 40mm WC.

10. Furnace pressure V. high condition should not be there.

11. Furnace pressure V. low condition should not be there.

12. HOTV should he closed.

13. Heavy oil/light oil trip valves/hydromotor valves to be closed.

i) All the secondary air heater are not off.

ii) The reheat protection signal in established.

iii) Adequate water wall circulation exists.

© PMI, NTPC 53

14) Pulverisers off condition should be there.

15) Feeders off condition should be there.

16) Hot air gate should be closed.

17) No flame condition should be there.

18) No boiler trip condition should be there. (Manual pressing of pushbuttons)

When all above conditions are satisfied "PURGE READY" bulb will' glow on the console insert. After

pressing 'Push to Purge' button purge will start for 5 minutes. After 5 minutes 'Purge complete'

indication will come. Within this time it is ensured that all unburnt particles have been removed from

the furnace.

If light oil firing provision is there LOTV can be opened now. Otherwise HOTV should be opened

and as well as heavy oil return valve should also be opened. For doing this we have push button on

FSSS console insert. By pressing OPEN push button the valve will open and RED indication will

glow. Initially the HORV is opened and when it is proved open, the HDTV is opened. Heated heavy

oil will be under recirculation. This is done to avoid condensation of high viscosity oil. HOTV will

open only when temperature of heavy oil has already reached more than 90oC and as well as heavy

oil and atomising steam pressure condition must also be satisfied.

HEAVY OIL ELEVATION 'AB' START:

Ho elevation AB start permit will be there when the following conditions are satisfied.

1) Air flow is greater than 3.0% and less than 40%.

2) The burner tilt is horizontal.

When any feeder is proven and in service for more than 50 seconds, above condition is no longer

required to satisfy oil elevation start permit.

© PMI, NTPC 54

There are two modes of firing oil in one elevation i.e. (1) on pair basis (2) on elevation basis.

The 'pairs' firing mode is selected when no feeder is in service. Elevation firing mode is selected

when at least one feeder is proven.

Pairs firing mode

Pairs are made for opposite corners i.e. pair 1 & 3 and 2 & 4. When pair 1 & 3 push button is

pressed the following events will occur.

i) The thirty second counting period is started.

ii) The seventy second counting period is started.

The oil gun No.1 will advance from the retracted position if the following conditions are there.

i) The gun No.1 is engaged.

ii) The corresponding scavenge valve is closed

iii) Heavy fuel oil isolation valve is proven open and as well as atomising steam isolation valve

is also proven open in the local control station.

Local gun maintenance switch in remote position.

The oil gun will advance and the 'Gun advance indication will appear on the console insert.

After the gun has advanced command will go to the HEA ignitor spark rod. Spark rod will also

advance. 'Advance' indication will come on the console insert for gun and as well as for ignitor. The

following things will occur.

i) If atomising steam valve is not opened, the oil gun will be retracted.

ii) Ignitor will start sparking once steam atomising valve is fully opened.

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iii) Heavy oil nozzle valve will also start opening. Indication will come on the console insert if oil

valve is fully opened.

The HORV is closed automatically. However if MFT occurs, HOTV will close automatically. Similarly

on atomising steam pr. low or fuel oil header pressure low also, HOTV will he closed automatically.

By this time oil gun should catch fire and scanner will sense the flame and give an indication on the

console insert "FLAME". After 25 seconds ignitor will retract to its original position and after 30

seconds command will go to corner No.3. Gun of corner 3 for AB elevation will get established in

the same manner as explained for gun No.1 when the seventy second counting period expire

corner trip signal is established if any of the following conditions is there.

i. The corner oil gun does not prove flame.

ii. The atomising steam valve is not open.

iii. Heavy oil nozzle valve is not open.

Pairs 2 & 4 can also be taken in service in the same manner as explained for pair 1 & 3.

Afterwards associated secondary air dampers will change from 'Auxiliary air' to 'Oil Firing' mode.

For this 3 out of 4 guns should at least be in service to fulfill 'oil elevation established' condition.

Elevation Firing Mode

Elevation firing mode is selected when any feeder is proven. By pressing elevation firing push

button guns are proven on pair basis only i.e. first 1 & 3 guns and then 2 & 4 guns in the same

manner as explained in pair mode basis. But out of 4 guns 3 have to be in service to satisfy 'HFO

elevation' in service condition. Otherwise "UNSUCCESSFUL START" indication will come and this

will not be a permissive for taking mills in service.

© PMI, NTPC 56

Oil Elevation Shutdown

If oil guns are to be removed pair 1-3 'stop' push button can be pressed and following events will

occur.

i) The heavy oil nozzle valve at corner No.1 will get closed.

ii) Steam scavenge valve will receive a open command. As well as steam atomising valve will

also receive a redundant open command. HEA ignitor receives an advance signal for 15

seconds.

iii) The moment scavenge valve gets fully opened a five minute counting period is started.

iv) After five minutes steam scavenge valve & steam valve will get closed.

v) Oil gun will get retracted to its home position.

vi) After 30 seconds command will to corner No.3 and same procedure will be followed as

explained for gun No.1 likewise pair 2 & 4 can also be stopped.

Pulverizer Operation

Prior to starting any pulverizer ignition energy must be adequate to light off coal. Mill ignition energy

condition is satisfied for all the mills when the following conditions are satisfied. This is called

ignition permit.

i) Any associated oil elevation in service i.e. AB/CD/EF, [A & B mills can be taken in service if

"AB oil elevation established" condition is there. Similarly C, D, E & F mills can be taken in

service when corresponding oil elevation is there in service.]

OR

ii) Adjacent feeder is in service and the feeder speed is more than 50% and boiler load is

greater than 30%.

© PMI, NTPC 57

The above conditions can be applied to any pulverizer to fulfill pulverizer ignition energy condition.

Pulverizer Ready

Prior to starting a mill, a "Pulverizer Ready" signal for the selected pulverizer must be established.

This signal is made ready when the following condition is satisfied.

1) 'Pulverizer start permit' condition should be there. For this the following conditions should be

satisfied.

a) The air flow more than 30% and should be 50%.

b) The burner tilt is horizontal.

c) 'No Master Fuel Trip' condition.

2) 'Primary air permit' signal should be established. There are two separate "Pulverizer primary

air permit" signals. One is for A, B & C and other is for D, E & F mills. Any one signal is

established when the following conditions are satisfied.

a) Both F.D fans and both P.A. fans ON

OR

At least one F.D. and one P.A. fan ON condition is there.

b) Hot PA duct presence of AB and C is not vary low for A, B and C and Hot PA duct pr.

of D, E and F is not very low for D, E and F (It is around 800 mmWC in normal

condition) 'primary air permit' signal is no longer valid for the mill which is already in

service.

3) Pulverizer discharge valves should be opened.

4) Pulverizer outlet temperature is less than 95oC.

5) Corresponding feeder is selected for remote control.

6) Cold air gate should be opened.

© PMI, NTPC 58

7) The Tramp iron hopper valve is proven open.

8) Feeder inlet gate is proven open.

9) Pulverizer 'Lub oil pressure satisfactory' signal should be there. This is there for 500 MW

Units where lub oil pump is there is in the pulverizer.

10) No pulverizer trip signal exists.

11) Satisfactory lub oil level and temp condition should be there.

Now pulverizer can be placed in service after the 'Pulverizer start permit', 'IGNITION Permit' and

"Pulverizer Ready' lights are on.

When we press the push button of the selected pulverizer, seal air valve will get opened and

differential pressure from seal air header to pulverizer underbowl should be greater than 200

mmWC. Afterwards pulverizer will get switched ON. Now following things will be valid for this

pulverizer.

a) Pulverizer discharge valve cannot be closed.

b) Pulverizer seal air valve cannot be closed.

c) The associated auxiliary air damper cannot be closed.

d) Hot air gate can be opened.

e) Feeder can be started.

f) Cold air dampers are opened to 100% position.

g) Hot air dampers can be operated.

© PMI, NTPC 59

After starting the pulverizer hot air gate can be opened and air temperature can be increased or

decreased to the required valve by operating cold and hot air damper. Afterwards feeder can be

started. After starting the feeder following signals will be made through.

1) Within 5 seconds coal flow should be established through the mill. Otherwise "Low current

Relay" set for 30% mill current will trip the feeder.

2) Within 180 seconds fire ball scanners should indicate "Flame" for the mill ignition energy to

get stabilized. Otherwise feeder will trip.

When pulverizer is in service following checks will be in operation.

1) Feeder speed will come to minimum when pulverizer bowl differential pressure is high.

2) No coal flow will trip the feeder.

3) A high pulverizer temp. will close the hot air gate and open the cold air dampers to 110%

position.

4) Seal air underbowl differential pressure is less than 125 mmWC for more than sixty seconds

will trip the pulverizer.

5) Pulverizer ignition energy not available will trip the pulverizer.

6) Primary air trip signal will trip the pulverizer

BOILER TRIP

Boiler trip signal is established if any of the following conditions exist.

1) Loss of ACS power for more than 2 seconds.

2) Loss of 220 VDC for more than 2 seconds.

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3) Loss of unit critical power for more than 2 seconds.

4) Drum level V. low for more than 10 seconds.

5) Drum level V. high for more than 10 seconds.

6) All boiler feed pumps off.

7) All ID fans off.

8) All FD fans off.

9) The air flow less than 30% before the boiler load exceeds 30%.

10) The deaerator level is V low. This needs. to be checked as this is not provided for 500 MW

units.

11) Inadequate waterwall circulation for more than 5 seconds.

12) All secondary air-heater are off.

13) At least two out of three pressure switches indicate a "higher furnace pressure" condition.

14) At least two out of three pressure switches indicate "low furnace pressure" condition.

15) Both BOILER TRP emergency push buttons are depressed.

16) All feeders off, (Not provided in 500 MW units).

17) Loss of reheat protection occurs.

18) Loss of fuel trip.

19) Unit flame failure.

© PMI, NTPC 61

Cause of Trip System

The first boiler trip command that causes a MFT will illuminate the appropriate indicator in the cause

of Trip Section on the console insert. Any successive boiler trip commands to the other indicators

are blocked. There will be only one indicator which will be glowing.

PRIMARY, SCANNER AND SEAL AIR FANS OPERATION

Primary air fan control: Primary air fans are used to transport the pulverized coal to the respective

coal burners at each coal elevation.

When MFT signal is established, the PA fans are tripped.

When the furnace purge cycle is completed and a No MFT signal is there, PA fans can be placed in

service. When all coal air dampers are positioned to less than 5% open, permit to start PA fans will

be established.

A 'primary air permit' signal is required before a pulverizer can be started.

Scanner air fan Control

There are two scanner fans in one boiler. One is AC scanner fan and other is DC scanner fan.

When both FD fans are off, the scanner air emergency dampers are opened. Otherwise scanner

fan inlet is there from FD fans discharge. Once the fan is started scanner outlet damper is opened.

In case of AC failure DC scanner fan gets started. Scanner air fans are provided, because scanners

are to be kept cool otherwise scanner lens will get damaged.

Seal Air Fan Control

There are two seal air fans for 200 MW unit, one seal air fan is used for supplying seal air to mills

and other is standby.

© PMI, NTPC 62

By pressing the seal Air fan start push button seal air tan will get started and its discharge damper

will also open. Seal air fan will get tripped when both P.A. fans are off.

Secondary Air Dampers Control

There are 13 elevation of secondary air dampers in a 210 MW boiler. This way total 52 nos. of

secondary air dampers are there at all the four corners of the boiler. Secondary air dampers are of

three type.

1) Auxiliary air dampers i.e. 4x4 = 16 Nos

2) Oil air dampers I .e. 3x4 = 12 Nos

3) Coal air dampers i.e. 6x4 = 24 Nos

Initially when boiler is not lighted up oil air dampers behave as auxiliary air damper and are

controlled from one module only in UCR i.e. the module of auxiliary air dampers. This way 7x4 = 28

Nos. air dampers are controlled to achieve wind box to furnace DP of 40 MMWC when boiler load is

less than 30% and it is around 100 MMWC when boiler load is more than 30%.

The moment oil elevations are taken in service associated air dampers are controlled by the other

module i.e. the module of oil air dampers. If on auto, operation of these dampers is governed by

heavy oil pressure. In case of oil firing dampers of AB, CD & EF elevations are controlled from oil

air dampers module.

There are 6 modules of coal air dampers for each elevation of pulverizer. When any feeder is not in

service coal air damper: cannot be opened. Once any feeder is started corresponding elevation of

coal air dampers can be operated. When on auto regulation of coal air dampers is governed by

feeder speed.

When boiler is tripped all secondary air dampers will get fully opened. Similarly in case of

compressor air failure or power failure these dampers will also open to full. It is called a 'fail safe'

arrangement. Closing and opening of other dampers are governed by the logics of FSSS.

© PMI, NTPC 63

FLAME SCANNERS

In our earlier 200 MW projects, we were using UV type flame scanners. However the UV type flame

scanners have not given satisfactory performance. The reasons for unsatisfactory performance of

these flame scanners are that the intensity of UV rays is very low resulting in poor sensitivity and

the deposition of ash on the shutter/detector tube blocks the sensing of actual flame.

In view of this it was decided to use flame scanners working on the principle of visible light detection

known as safe scan. These scanners use a photodiode to detect the flame and a fiber optic light

guide.

OPERATION

The visible-light scanner is designed to monitor the characteristic frequencies and intensify levels of

visible light emitted from the combustion of fossil fuels. Light is transmitted from the windbox by a

fiber optic light guide and converted-to an electrical signal by a photodiode. Both the flame intensify

and the frequency of the flame pulsations are amplified by electronic circuitry at the boiler side and

converted to a current signal suitable for transmission to remote equipment.

In the remote equipment, three parallel circuits receive the flame signal from the boiler-mounted

equipment. These circuits simultaneously and independently examine the flame signal for absolute

magnitude, intensify, and frequency. The existence of all three components in a specified range is

required before acknowledging that it "sees" flame. A simplified system block diagram, which shows

signal paths from the light guide to its various outputs, is shown in Figure 21.

© PMI, NTPC 64

The fault detection circuit constantly compares the flame signal magnitude against fixed high and

low limits. If a fault, such as broken cable, occurs anywhere between the photodiode and the

remote chassis, the flame signal will deviate from an established range of good signals. A

comparator circuit will detect this deviation, initiate a fault alarm, and disable the flame permissive

signal.

© PMI, NTPC 65

4. Role of Analytical Instruments in TSB Stations

INTRODUCTION

The availability, reliability and efficiency of a boiler turbine unit hinge around the close control of the

chemical regimes of the working fluid i.e. water/steam in the circuit as well as the combustion in the

boiler. The instruments monitoring the chemical regimes and combustion are generally called

Analytical Instruments. These instruments in a Thermal Power Station fall under three categories

namely:

i. Water/Steam Analyzers

ii. Gas Analyzers

iii. Smoke monitors

The following sections will broadly deal with the role of the above instrumentations with regard to

their application and interpretations of the movement with the process behaviour.

WATER/STEAM ANALYSERS

To minimize the generating cost, the unit sizes have grown from 30 MW to 500 MW in a short span

of time. This has to considerably increase the last stage blades of the turbine. In a 500 MW the

blades have grown to as large as 33 inch creating more possibilities for salt deposits. Deposits of

this kind cause:

• Unbalance of rotating mass producing vibrational problems.

• Stress corrosion leading to cracking and catastrophic failure.

• Loss of aerodynamic efficiency.

© PMI, NTPC 66

Thus the purity of steam which transports impurities (like Nitrates, Sulphates, Nitrates, Organic

matters, Copper, Iron etc.) into the turbine has become very stringiest and the chemical controls

exercised to limit the impurities in PPb level. These impurities that are likely to join the working fluid

to the boiler can originate from one or more different sources.

1. A condenser leak.

2. Contaminated make up water caused by faulty demineralisation.

3. Contaminated water in the steam - drain the recovery system.

4. Corrosion products from an improperly treated feed system.

5. Other sources peculiar to a particular Power Station Plant Design (e.g. a faulty non return

valve in the circulating water system of a rotary pump vacuum raising plant permits

circulating water to enter the condenser).

The various constituents that enter water are classified in accordance with the troubles they create:

• Corrosive substances

• Scale forming substances

• Foam forming substances

Mechanical entrainment of boiler water in the steam and vapours carry over of dissolved salts are

considered to be the leading mechanism for introducing of impurities into the turbine. From the

theoretical considerations, the carry over is significant only at high pressures. This is because the

fraction of boiler impurities going to the steam is an exponential function of the steam density

making the fraction significant at pressures above about 130 Kg/cm2 in normal utility boiler.

Although improvements in turbine materials and designs are attempted to improve their reliability,

yet tighter control of water purity is considered to be the best approach.

© PMI, NTPC 67

Since the turbine manufacturers have been steadily reducing the acceptable limits for impurities in

steam, the impurities in trace levels during normal operation and their wide variation during start-up

and other emergency conditions can build up to harmful levels. The concentration in steam does

not pose much problem in high pressure section of the turbine; however they deposit over the

regions where the pressure and temperature fall in the flow path. Continuous introduction of such

steam transported chemical is to be avoided. It is therefore essential that the plant operators should

be correctly informed on the purity of water and steam in their system at all times, and advised of

changing conditions that could signal potential troubles.

The following steam purity limits recommended by turbine manufacturers will show the gravity of the

situations.

Limits Constituent

Normal 100 Hrs. 24 Hrs.

1. Cation Conductivity (mho) 0.2-Oa3 0.3-0.5 0.5-1.1

2. Sodium Parts per billion (PPb) 3 – 5 6 – 10 10 - 20

3. Chlorides (PPb) 5 5 – 10 10 - 20

4. Silica (PPb) 10 10 – 20 20 - 50

5. Iron (PPb) 20 - -

6. Copper (PPb) 2 - -

7. Oxygen (PPb) 10 10 – 30 30 - 100

Installation of proper type of analytical instrument to monitor water chemistry, interpretation of their

information properly, and prompt follow up and remedial measures provide the cheap insurance

cover for the life of the plant and avoid unplanned shut downs. Modern units are also provided with

automatic chemical controls to maintain the chemical regimes.

A good monitoring system serves two functions.

i. It measures that the water and steam meet prescribed chemical limits.

ii. It detects contaminants entering the system thus aiming:

© PMI, NTPC 68

• To keep track of performance of individual parts of the plant and hence the plant as a

whole.

• Presentation of failure by early diagnosis.

• To achieve a high standard of reliability and maximum plant availability.

• To identify the cause in the event of failure from the recorded data.

Since the plant availability is a function of the quality of the working fluid viz water/steam, the plant

operators require continuous information about his plant in respect of the following s

• The foundation of protective layer and the inhabitation of corrosion between the condenser

and the boiler inlet.

• The growth and preservation of the protective layer and avoiding of deposits and corrosion

in the boiler.

• The prevention of deposits on the turbine blades.

• The ability of condenser materials to withstand the corrosion.

The choice of parameters to provide the above information depends upon:

1. The type of steam generator

2. Recommendations from equipment suppliers

3. System metallurgy

4. Operating conditions and they should take care of

• Operational safety and reliability

• Providing information about long-term performance.

• For any specific research purposes.

In order to ensure the above, the sampling system must be well designed to have a representative

sample. In the case of contaminants, multiple sampling system should pin point problem such as

© PMI, NTPC 69

condenser leakage, contaminated make up water, or substances being picked up from interior

components. In general sampling should be taken from all major fluid containing components like:

• Cooking system

• Make up water

• Steam generating system

• Condenser system

Fig.22 gives the modern water/steam analyzers and their possible locations. Table given below also

lists out the various instrumentation in the water/steam circuit.

© PMI, NTPC 71

POWER PLANT WATER ANALYSIS

Sample Point Conductivity Cation

Conductivity

PH Socium Na

Oxygen (O2)

Turbidity Hydra-Zine

N2OH4

Silica (SLO2)

% H2 in steam

Hot well

Condensate Pump

Deaerator inlet

Deaerator outlet

Economiser inlet

Boiler Drum

Blow down

Main Steam

Apart from the above on line analysis, periodic laboratory analysis are carried in some cases for

iron, copper, phosphates and ammonia. Laboratory analysis are also carried out to calibrate on line

instruments.

The control ranges for on line instrument will be such that, they will give good response at normal

operating concentrations and at the same time they will be able to indicate abnormal

concentrations.

PARAMETERS BEING MEASURED AND THEIR IMPORTANCE

On-line analysis of number of parameters are essential by automatic instrumentation. The following

few are the most important among them.

SODIUM

Sodium measurement is more sensitive, than conductivity to detect the condenser leakage.

Condenser leakage adds to the system specific corrosive such as Sodium Hydroxide and Sodium

Chloride. Therefore it is essential that an immediate indication is given of any condenser leak so

that the chemist and operator can take the necessary action to the unwanted impurities which enter

the condenser and subsequently the feed and the boiler waters. The chemist will probably dose

© PMI, NTPC 72

additional chemical treatment to minimize the effects of the impurities and the operator will be told

by the shift charge engineer to commence boiler blow down.

In modern power stations, the sensitive method of detecting condenser leaks is to measure and

compare the concentration of sodium in the steam which will be negligible and in the condensate

(also negligible under favourable conditions). When either a condenser leakage occurs or impurities

enter through other sources, sodium enters the system and increases the concentration in the

condensate relative to that in the steam.

Sodium salts are extremely soluble and can cause severe boiler and turbine corrosion. Sodium is

therefore measured in:

a. Saturated Steam

The level of sodium after the boiler and before the super heater indicate the amount of carry over

from the boiler and can be used to control.

• The boiler water level

• Anti-foam dose rates

• The load on the boiler

b. Condensate

The measurement is carried out at the extraction pump discharge point to check the ingress of

cooling water into the condensate.

METHOD OF MEASUREMENT

Sodium is measured by electro chemical method. Where a selective sodium ion electrode is

immersed in the sample along with a reference electrode. The potential developed across these

electrodes is a measure of sodium ion concentration and when connected to a pH meter, it makes it

possible to measure sodium in ppb level.

© PMI, NTPC 73

The unit of measurement is ppb (parts per billion) which is the same as gm/litre or parts per 109.

SILICA

Silica (Si02) is one of the main constituents of sandy and clay soils. Water which has percolated

through these soils tends to pick up silica and unfortunately this is not easily removed.

Silica is slightly soluble in steam and it can be carried from boiler to turbine where it will tend to

deposit on the turbine blades. The higher the operating pressure and temperature, the greater the

solubility of the silica, so that less silica can be tolerated in higher pressure boilers than in lower

pressure boilers. The concentration of silica in boiler water must, therefore, be kept as low as

possible. For example boiler operating at 100 bar can tolerate a silica level of 1.2 p.p.m where as

145 bar boilers can tolerate only 0.4 p.p.m silica.

Once silica has entered a boiler water it can be removed only by blow down.

Silica which enters the boiler poses a problem to the power generation due to its tendency to build

up in the boiler tubes thus impeding their efficiency or in extreme cases causing mechanical failure.

To reduce the risk of reduced operating efficiency, water is treated before use in boiler. As complete

removal is not possible, silica build up occurs in boiler and on turbine blades.

Turbines spins at 3000 rpm to generate 50 HZ power. Tip of the turbine blades at this speed will

rotate at a velocity equal to twice that of sound inside the clearances which are of the order of a

millimeter. When deposit occurs over the blades, this clearances are hampered with and turbine

looses efficiency, unbalance created, developing vibration leading to failure of the turbine.

In order to trace the passage of silica through the system, it is monitored at the following points.

a. Boiler Water

To check the silica levels in the boiler drum and to effect the blow down,

© PMI, NTPC 74

b. Saturated Steam

To get the final silica level being carried to turbine.

This guides the boiler operation like:

• Blow down

• Boiler load control


On line silica analyser is an automated version of the molybdenum blue calorimetric method in

which the intensity of colour developed by adding reagents to the sample is measured

photometrically to give an indication of the concentration of silica in the sample. Because the colour

reaction takes time to develop fully, the analyzer is not a continuous monitor, but operates on a

cycle time of 12 minutes i.e. a fresh sample is abstracted and analyzed every 12 minutes and the

electronic read out system 'holds' the result of the analysis until the next cycle is performed and

updates the result.

DISSOLVED OXYGEN

Corrosive substances are in the form of acid in solutions or as dissolved gases like carbon-dioxide,

oxygen, hydrogen sulphide, ammonia etc. Carbon dioxide and oxygen are dissolved in the feed

water due to air ingress under vacuum or through leaking steam under pressure. These two gases

can-cause so much troubles in a power station particularly in the feed system and boiler.

Dissolved oxygen hastens the corrosion when present where metal is in contact with a solution by

setting up electro chemical reaction as given:

2Fe + 02 + 2H20 = 2Fe (OH)2

Dissolved oxygen affects the plant and leads to plant failure in a number of ways.

© PMI, NTPC 75

• It attacks the protecting oxide coating.

• It will remove the copper and iron from the feed pipe line which will be deposited in the boiler

leading to efficiency loss, overheating and ultimate failure.

• Uneven distribution of oxygen in water sets up electro chemical action leading to severe

pitting.

In order to avoid the above reactions and damage, the oxygen level should be restricted to

minimum possible. There are a number of methods both mechanical and chemical available to

remove the oxygen dissolved in water. In. power stations depending upon the design of the unit,

these methods are employed and deaeration is done in three stages.

DEAERATION IN THE CONDENSER

Make-up water is fed to the, condenser in the form of spray into the condenser above the water

level allowing very large surface area to be in contact with condenser vacuum. This makes the

deaeration very efficient, here the water is deaerated to a level less than 015 p.p.m. However

leakage through glands etc. hampers with this level.

DEAERATION IN DEAERATOR

Steam is blown into a deaerator and the feed water is sprayed in the atmosphere of steam. The

steam reduces the partial pressure of the gases above the water and thus makes the gases Hess

soluble in water and are swept away. An efficient deaerator can reduce the concentration of

dissolved oxygen level less than 0.005 p.p.m.

CHEMICAL DEAERATION

Mechanical deaeration discussed above cannot alone maintain the oxygen or carbon di-oxide

concentrations to an acceptable level in a modern power plant. Chemical deaeration is also

required not only to remove or neutralise the gases that have escaped mechanical deaeration but

© PMI, NTPC 76

also to cope with those gases that enter the system through the leakages or as a result of poor

operation of condenser or deaerator.

In modern stations liquid chemical called Hydrazine (N2H4) is used to remove the oxygen from the

feed water. This chemical Ls dosed at the outlet of deaerator. The following reaction takes place.

N2H4 + 02 = N2 + 2H20

N2 and H2O are harmless components for boiler. Ammonia and nitrogen which will protect the

steam system.

It is therefore important to measure the dissolved oxygen and hydrazine by on-line analyzers.

Dissolve oxygen measurement is done for:

• Protecting equipment against corrosion.

• Determining the effectiveness of non-condensable gas removal system.

• Detecting the hot well air leakage,

Dissolved oxygen is measured continuously in the following points :

Deaerator inlet/ outlet - To check efficiency of deaeration.

Economiser inlet - To check the performance of the oxygen scavenging reagent.

Condensate pump discharge - To check for leakage.

MEASURING SYSTEM

Dissolved oxygen is measured by any one of the following methods:

i Conductometric methods

© PMI, NTPC 77

ii. Amperometric method requiring external polarising voltage.

iii. Galvanometric type self polarising

All the above methods work on electro chemical cell principles and involve lot of maintenance.

HYDRAZINE MEASUREMENT

Hydrazine concentration is measured as insufficient quantity leads to corrosion and excess is

wasteful. Hydrazine is measured, at the economiser inlet. Modern power stations use automatic

chemical dosing on this measurement.

Hydrazine is also measured by electro-chemical principle.

CONDUCTIVITY

Conductivity and catonic conductivity indicate concentrations of treatment chemicals and

contaminants in the system.

This is still the simplest and most reliable measurement and is therefore employed widely. The

analyzers permit the identification of contaminants sources so that the operators can take

corrective-action. The conductivity measurement can be used as a direct control signal for the

ammonia chemical feed pumps. It is used to give the measurement of the total concentration of

ionic species (and therefore impurities) in solution. Where ammonia or volatile amines are present

like in condensate or feed water, conductivity is increased not, only by unwanted impurities but also

from treatment chemicals added deliberately. In such cases conductivity is measured after passing

the sample through cation exchange columns which remove the ammonium ion the high

conductivity of which masks the presence of other species and also increase the sensitivity of the

reading.

Conductivity is measured at:

a. Economiser inlet - to check the quality of the feed water.

© PMI, NTPC 78

b. Boiler drum - to indicate the need for blow down.

c. Saturated steam - to indicate the degree of carry over.

d. Condenser outlet - to detect condenser leaks.

e. Extraction pump discharge - to detect condenser leaks.


Conductivity is a measure of electrical resistance. A conductivity cell used to measure water purity,

consists of two electrodes immersed in the water. The electrodes are connected externally to an

electrical supply and meter. If the water contains a large number of impurities, the current is easily

conducted through the water and the electrical resistance, therefore, is low. The current is

conducted between the electrodes of a conductivity cell by ions from the impurities in the water. The

more ions that are present, the higher the conductivity indication. A conductivity meter is calibrated

in micro-siemen which are reciprocals of Mega ohms. Conductivity is proportional to resistance.

Relatively pure water has high resistance and therefore low conductivity. Impure water has low

resistance and therefore high conductivity.

Sea water gives a conductivity indication of about 50,000 micro Siemens where as condensate

should give less than 0.3 micro Siemens.

PH MEASUREMENT

pH is a measure of Hydrogen ion concentration in a solution. It is the negative log to the base ten of

Hydrogen ion presence. Thus it measures the acidity alkalinity of the solution under test. In most

boiler systems, chemicals are added to the feed water to control the pH (acidity/alkalinity) and

remove oxygen. Typically, pH is maintained on the alkaline side-at about 8.8-9.5 to prevent the

acidic attacks on system tubes and pipes. pH also gives indication about the leakage of acid

forming contaminants into the system.

© PMI, NTPC 79

In normal practice, copper alloy tubes are used in condenser and LP heaters while HP heaters are

fitted with carbon steel tubes. Carbon steel requires a mildly alkaline pH of about 9.5 for best heater

operation; whereas for the life of the non ferrous metal tubes the pH should be between 8.8 to 9.0.

Thus for a system having both ferrous and non-ferrous metal tubes a compromise value of pH

around 9.2 is recommended. If stainless steel is used instead of carbon steel, then feed heaters can

be operated at a pH compatible with copper base alloy (i.e. around 9.5).

It is important to minimise the corrosion rate of copper base alloys in steam systems because

copper picked up by the feed water in condensers and feed water heaters later plates out in boiler

tubes and on turbine parts. This sets up galvanic cells with ferrous alloys, causing local corrosion of

heater and .turbine components.

Therefore a close measurement and control of pH is essential to avoid acid attack on ferrous

components or alkaline attack on non-ferrous components. Further the stable build up of the

protective magnetite layer is also dependent on- the chemical condition prevailing. Modern power

station requires to measure this parameter to an accuracy of ± 0.05 within a 0.2 pH band.

MEASURING SYSTEM

pH measured by determining the e.m.f. produced by electrolytic action between two electrodes

immersed in the solution this e.m.f. being directly proportional to the hydrogen ion concentration.

The two electrodes can be in one unit or two separate units. One, the active cell usually made out

of glass produces a voltage which is proportional to the hydrogen ion concentration. A second cell

is used for reference purposes, the reference cell is generally made with calomel, which is a

compound of mercury.

SAMPLING AND SAMPLE PREPARATION

In most of the power stations it will be a common scene that analysers had been abandoned to

disuse. The major problems with analysers are associated with their sampling and sample

conditioning system. In recent years since the rolls played by analyzers grew to a greater

proportion, a much dependable sampling and sample conditioning system had to be developed and

put into use.

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Most analyzers today are relatively fragile instruments. Therefore, they are being mounted on a

panel located in a central location. All samples are brought to this location. Since many of these

samples points will be far from a central analyzer panel proper velocity of sample flow is being

ensured by right selection of sample pipe size and the lag time is limited within 60 seconds.

The sample flow is indicated by panel mounted rotameter.

© PMI, NTPC 81

GAS ANALYSIS AND SMOKE MONITORS

INTRODUCTION

Fuel accounts for 90% cost of electricity generation. Therefore it is the demand of the day to burn

the fuel efficiently and utilizes the heat thus released effectively without wastage. Thus the flue gas

analyzers play a major role in modern power plants where a huge amount of coal is being burnt

every hour to monitor and control the combustion.

COMBUSTION MONITORING INSTRUMENTS

Fuel requires adequate amount of air to provide the required oxygen to burn the combustibles

completely. A combustible like carbon which is a major-constituent (40%) of coal, if supplied with

adequate oxygen burns to carbon-di-oxide (C02) and release 33940 KJ/Kg amount of heat. But if

the oxygen becomes insufficient, it will burn to carbon monoxide and release only 10120 KJ/Kg

amount of heat thus incurring a 70% loss in heat release. It is, therefore, essential to provide

excess amount of air to ensure the required oxygen for combustion. But too much excess air also

causes efficiency losses on the fact that in the air supplied only oxygen (i.e. 20.9% volume) only

takes part in the combustion and the rest 79.1% Nitrogen inertly a heat carrying gas which enters

the boiler at the ambient condition and leaves the boiler at a very high temperature. In addition

excess air also leads to extra fan power and super heater temperature control problems. In order to

keep all these losses a minimum and improve upon the boiler efficiency boiler is to be operated with

optimum amount of excess air necessitating a close monitoring arid control of combustion.

Combustion conditions are monitored by:

• A meter to measure the amount of carbon-di-oxide in flue gas, (the operator keeping the

reading as high as he can).

OR

• A meter measuring the amount of oxygen in the flue gas (the operator keeping the reading

as low as he can without generating smoke).

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OR

• A meter measuring the carbon monoxide (the operator aiming for a lowest reading).

OR

• A meter showing the smoke density.

SMOKE

It had been the practice till recent time to adjust the combustion, air on seeing the colour of the

smoke. Special provisions were made in some units for directly viewing the chimney smoke from

the control room. A bad combustion generates smoke. But this was found to be a crude way of

assessing the combustion since there were no reliable instrumentation for this and the human eyes

sense the smoke colour on a logarithmic scale.

Therefore the modern day boilers rely on the measurement of any one of the flue gas constituents

like CO2%, O2% or CO%, the value of which provide the necessary information to analyze and

assess the quality of combustion. Any of the components mentioned, individually or collectively can

be a guide to optimum combustion with varying degrees of suitability. The selection of the

component of flue gas for combustion assessment is based on the following consideration.

i. The availability of proven, simple, measuring techniques and instruments to provide a

reasonably reliable, fast response of the change in the components.

ii. The components possessing an unambiguous correlation to the combustion conditions, i.e.

the percentage of selected component corresponds to a definite quantity of

excess/insufficient air for the combustion.

iii. The components should essentially be independent of fluctuations in the composition of the

fuels.

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CARBON-DI-OXIDE (CO2)

Monitoring of carbon-di-oxide as a guide for combustion has been in vague for a long time.

When a fuel such as coke (having no hydrogen) is used and exactly the right amount of combustion

air is admitted the flue gas generated will contain exactly 21% CO2 being the percentage of oxygen

in air. But of ordinary fuels contain hydrogen which combines with part of the oxygen in the air and

forms steam. This condenses and does. not appear in the gas analysis. Thus even without excess

air the percentage of CO2 will be less than the theoretical maximum of 21%.

In practice about 12% to 15% will be the best obtainable percentage when ordinary bituminous coal

is used owing largely to the fact that complete intimate mixture of the fuel and air never takes place.

The admission of excess air will not effect the actual volumes of CO2 being produced but will dilute

it with the result that the CO2 percentage will fall and the presence of the excess air will be

immediately shown by the reading of the CO2 meter.

In the recent time, the boiler combustion technology has witnessed a decline in its importance as a

guide to a combustion due to the following reasons.

i. The CO2 concentration is ambiguous since the same concentration can occur for two

different values of air quantity, one under insufficient air and the other under excessive air.

This happens so because the peak concentration of the CO2 occurs when the ratio

Actual air supplied

Stoichiometrically required amount of air

ii. The percentage of CO2 in the flue gas definitely depends upon the type of fuel and its

composition being burnt. The variation in hydrocarbons will change the percentage of CO2 in

flue gases.

For coal 40% excess air produces about 15% CO2.

For oil < 40% excess air produces about 16% CO2.

For gas < 40% excess air produces about 12% CO2.

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iii. The measurement of CO2 suffers a great deal in accuracy with the presence of Hydrogen

and SO2 since the thermal conductivity of both these gases vary in amount and direction.

These shortcomings make the CO2% quite inadequate for the determination. However the

most efficient percentage of CO2 will vary

• The hydrogen carbon ratio

• The physical condition of the fuel

• The volume of combustion chamber/grate area relation

• The method of firing

• The available draft


Orsat apparatus is the chemist instrument for determining the CO2% along with other flue gas

components like CO and O2. In this apparatus a sample gas is drawn by means of a hand bulb. The

apparatus as shown in fig.23 consists of a water cooled measuring cylinder and three absorption

bottles containing chemicals namely

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Bottle A containing potassium hydroxide solution to absorb CO2.

Bottle B containing an alkaline pyrogallol solution to absorb O2.

Bottle C containing acid cuprons chloride solution to absorb CO.

After passing the sample through the individual bottles, the sample is brought to the measuring far

which shows the amount of the gas component absorbed by the chemical and thus determining the

volume percentage of CO2, CO and 02.

ON-LINE ANALYSER

The on-line analyzer work on the principle of thermal conductivity. The measure of how well a

substance conducts heat is called its thermal conductivity. If the thermal conductivity of a mixture of

© PMI, NTPC 86

two gases is known, it is possible to calculate the ratio of each gas.

Flue gas consists of nitrogen, oxygen, carbon monoxide (all having thermal conductivities about the

same) together with carbon-di-oxide. The mixture behaves as if it were a mixture of two gases and

if the thermal conductivity is measured, the fraction of carbon-di-oxide present can be determined.

The measuring system is a wheat stone bridge with two of its arms are made of platinum wires fixed

on metal blocks. One wire is surrounded by the gas being measured. The other wire is sealed in a

reference gas. Both the wires are heated by the bridge supply. The temperature of the wires and in

turn their resistances will depend upon the cooling effect of the gases. Thus the unbalance created

is measured by a galvanometer calibrated in temperature scale.

The presence of an unknown amount of water vapour will cause errors in the reading. The sample

and reference gas should therefore be either both dry or both saturated with water.

OXYGEN IN FLUE GAS

For complete combustion of a fuel certain amount of oxygen is required assuring that the

combustion time is infinite. In a furnace, however, combustion burst takes place in the shortest

possible time for maximum burning efficiency. So extra oxygen must be supplied in the form of

excess air to accelerate the combustion process. As all the oxygen is not required some is

discharged in the flue gases and a measure of this excess oxygen concentration is a measure of

the efficiency of combustion in the furnace. However, in the interest of fuel economy there is a limit

to the amount of excess air which should be supplied as the stack losses then become excessive.

Hence the lower the reading of the O2 meter, the less heat is being wasted by excess air.

The O2% is found to be a favourable component for combustion guide as it does, not depend upon

the fuel composition. It has a quite linear characteristic with the excess air. It has a very consistent

relation with the excess air; almost for all composition of fuel.

Yet, as the trend towards greater efficiencies continued, another parameter was required as a

complementary to the excess oxygen measurement. This was so due to the following limitations of

oxygen analysis.

© PMI, NTPC 87

• Various burners under different conditions and loads burning oil, gas or solid fuel require

different levels of excess air to give complete combustion. Thus the important question is

"what level of oxygen is required" ?

• Since boilers operate with negative combustion chamber pressure a certain amount of air

ingress is inevitable. This air ingress causes direct and serious errors in oxygen

measurement.

• At low excess air levels, small changes in oxygen level is undetectable and thus the control

becomes less sensitive.


Conveniently oxygen is being measured utilizing the fact that oxygen is the only constituent in flue

gas that has paramagnetic property (i. e. attracted into a magnetic field).

The magnetic wind principle on which the measurement is done is shown in Fig.24. The flue gas

sample flows round the annular chamber, across which is mounted a thin glass tube carrying a

platinum winding through which a current is passed to heat the tube. The winding is centre tapped,

© PMI, NTPC 88

each half forming one arm of a wheat stone bridge. The left half winding is subjected to a strong

magnetic field produced by a permanent magnet. The gas sample containing oxygen is attracted

into the field at the left hand and of the cross tube; the velocity being proportional to the oxygen

concentration in the gas sample. This wind cools the left hand arm of the winding more than the

right hand arm causing the resistance of the left hand arm to be less than the right hand arm. The

resulting bridge unbalance is picked up by a self balancing potentiometric recorder and the result

appears as an oxygen percentage.

The conventional oxygen analyzer described above had the following drawbacks:

i A costly and unreliable sampling and sample conditioning system involving lot of

maintenance.

ii. Long time delay before the results are known.

iii. Analysis was on the basis of 'DRY' sample rather than 'WET' or 'TOTAL' sample

A new 'In-site' the instrument based on Zirconium oxide cell have come into practice overcoming

the drawbacks listed. This cell when inserted into the flue gas path develops a voltage across the

two sides when each side is exposed to different oxygen concentration. The phenomenon is

described by the nearest equation.

RT P1 (O2)

i.e. e.m.f. = LogN + c

4F P2 (O2)

where e.m.f. = cell output voltage

R = gas constant

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F = Faraday’s constant

P1 (O2) = Reference air partial pressure.

P2(O2) = Sample gas partial pressure

C = Cell constant

T = Absolute temperature

In practice, the temperature is maintained constant by a heater element and air (20.95% oxygen) is

used either through a pump or from instrument air supply as reference air; then the output becomes

inverse logarithm of the partial pressure of oxygen in the measured gas, Fig.25 shows the system

working.

CARBON MONOXIDE

Because of the drawbacks already discussed oxygen level can only tell the operator what the

efficiency level is, since the efficiency level is directly related to the excess of air fed to the

combustion chamber. But carbon monoxide provides the operator to obtain maximum operating

efficiency. Thus, together, carbon monoxide and oxygen provide the complete picture for the

operator.

CO determines the level of attainable efficiency and oxygen measures it. In addition CO

measurement possesses has the following advantages:

i. The control point on the basis of CO level is unaffected by variation on boiler load, design

type, duel type etc. which influence 02 level.

ii. In leakage air does not affect the measurement results since the CO level is of the order of

PPm.

iii. CO directly detects the maldistribution of combustion air by being present in appreciable

level even while having high level of excess oxygen.

While operating a boiler or furnace, the CO meter should record a minimum level typically 100 PPm

- 150 PPm.

© PMI, NTPC 92

METHOD OF CO MEASUREMENT

The measuring principle utilizes the fact that heteroatomic gases absorb infra-red radiation at wave

lengths which are characteristic for each gas between 2.5 and 12. Carbon monoxide one of such

several gases that will absorb infra-red radiation of a particular wave length. The amount of

absorption depends on the concentration of carbon monoxide in the gas being tested, so if the

absorption is measured the percentage of carbon monoxide can be determined.

Fig.26 shows a typical instrument. Radiation from two sources is passed through parallel path; first

through identical filter cells containing gases (such as carbon dioxide) which might be present in the

measured gas and that also absorb infraradiation. Thus both beams loose that frequency of

radiation removed and the error due to such cross action is eliminated.

Then, one beam passes through a measuring cell containing the sample and the other passes

through a reference cell filled with Nitrogen, a non absorbing gas. The measuring cell absorbs the

radiation depending upon the CO level in the sample gas. The receiver system then receives the

beam from the two-cells. The receiver is a chamber in two parts divided by a membrance each

containing pure carbon monoxide which absorbs the radiation and so heats up thus increasing its

pressure. If the two beams of radiation are unequal (due to carbon monoxide in the gas being

measured) the pressures in the receiver will be unequal, thus causing the flexible metal diaphragm

to move in relation to the perforated plate. The two plates together form a capacitor.

The infra-red beam is made intermittent by a rotating shutter. Thus the capacitor alternates in value

as the diaphragm moves. A direct voltage is applied to the capacitor and the resulting signal is

amplified and fed to a recorder.

© PMI, NTPC 94

CHIMNEY EMISSIONS

INTRODUCTION

The problems of atmospheric pollution has been with us since the discovery of fire and has been

intensified by the use of coal in the home and in industry. Since the airborne pollution is in an ever-

increasing range and also is considered to be "prejudicial to health".

POWER STATION POLLUTION

Thermal power stations take all reasonable steps to combat chimney emission by the installation of

efficient fuel burning plant, supported by efficient extraction apparatus. It is also the intention to

monitor continuously every power station chimney for dust and dark smoke.

NUISANCE OF POLLUTION

Smoke causes the following two types of nuisance.

i Visible pollution by smoke, grit and dust.

ii. Pollution by invisible gases, the most harmful being sulphur dioxide.

SMOKE

The definition of smoke states that it consists of particles less than 1 micron in diameter (0.001 mm

= 1 micron). The particles consist chiefly of carbonaceous matter including tar. It results from

incomplete combustion.

GRIT AND DUST

Grit and dust particles are larger than smoke particles and may be classified arbitrarily as follows:

© PMI, NTPC 95

Dust: 76 micron to 1 micron particle sizes.

Grit: Over 76 microns particle sizes.

EMISSION ESTIMATION

The stack emission in a power station has a wide range of particle sizes ranging atleast from 1

micron to 100 micron. The fine dust in the range below 10 micron is largely responsible for the

visibility of the plume. These finer dust particles do not present a serious pollution problem as these

are carried away by wind to much wider area.

But the coarser particles over 10 micron grain sizes land in the building and property within 2 to 3

miles and are the main cause of dust pollution.

Based on the above segregation of dust on particle sizes there are two types of instruments in

practice - one measuring the smoke density and the other measuring the dust burden.

SMOKE DENSITY METERS

The on line smoke density meters record the optical density of the flue gases. These instruments

are designed to use the obstruction of visual light as a reference and so are essentially electric

optical instruments. To provide good degree of resolution and for true correlation, they utilize the

same spectrol response range as the human eye.

In one range of instruments the energy loss of a focused light beam caused by the dust particles. in

the emission is measured and expressed in the optical measurement "Extinction". The quantity of

dust contained in the emission through which the light passes is proportional to the extinction value.

MEASURING SYSTEM

The Fig.27 shows the system with its optical bead mounted on one side of the stack, and the

reflector unit on the opposite side. The optical head contains the light source, a photo receiver and

electronic assemblies for signal generation. The reflector unit is a passive assembly without any

electronics.

© PMI, NTPC 96

The light transmitter in the optical head emits a uniform beam which is modulated at 1.5 KHZ by a

rotating aperture disc and impinges on a segment disc. The aperture disc and the segment disc are

on the same drive shaft. The segment disc is so designed that, for a quarter revolution, the light

beam is either reflected on the surface of the disc or allowed to pass across the stack via an

opening in the disc.

The reflected light beam is passed on to the photo-receiver via a beam splitting mirror. A quarter

revolution later the same beam splitter directs the measuring light after it has passed across the

stack - to the receiver. A photo-cells converts these light beams into electrical voltages which are

compared and an output is generated to be passed on to the recorder on the relation that

Extinction E = log 1/T

where, T = Transmission factor = I/I0

I = Illumination received

10 = Illumination emitted.

DUST MONITORS

As has been already stated, coarser-particles above 10 microns sizes are not monitored by these

methods and do not have any marked effect on plume visibility, but is entirely responsible for the

settlement of dust objects at ground level and is the main cause of complaints of dust pollution.

© PMI, NTPC 98


The dust monitor consists of sampling unit as illustrated in Fig.28 and the nozzle of this unit is

pointed into the flue gases so that the finer particles are carried around it but the coarser, particles

enter the nozzle by their own inertia. These particles settle on the lower glass window and a beam

of light is projected from a lamp outside the duct through the collected dust and back to the photo

cell as shown. This photo cell forms part of one arm of a modified wheat stone bridge circuit

(Fig.28). The output from the bridge is then transmitted to an electronic recorder. The signal

received by the recorder varies according to the intensity of the light by the photoelectric cell and

therefore varies inversely to the amount of dust on the window.

The collected dust is cleared by a blast of compressed air after a set period - usually 15 minutes

and the window is automatically wiped mechanically every 24 hrs. For older units where the dust

arresting equipments are poor, the collecting time could be reduced to one quarter.

© PMI, NTPC 99

5. Automatic Control

Automatic control is used on Power stations for safe and efficient operation of the plant. The type of

automatic control used varies from Simple Pneumatic control systems on auxiliary plant to

Microprocessor based control systems on main plant loops. Although the two systems are much

different in their complexity, to understand either system we must first understand basic automatic

control theory.

When talking about automatic control theory certain standard terms are used. A list of the basic

terms is written below.

BASIC AUTOMATIC CONTROL TERMS

PROCESS The act of physically or chemically changing, including

combining, matter or of converting energy.

PLANT Installation in which process is carried out.

CONTROLLED CONDITION The physical quantity or condition of the controlled body,

process or machine which is the purpose of the system to

control.

CONTROL SYSTEM An arrangement of elements interconnected and interacting in

such a way as to maintain or to affect in a prescribed manner,

some condition of a body, process or machine which forms

part of the system.

DESIRED VALVE The valve of the controlled condition which the operator

desires to maintain.

MEASURED VALVE The actual value of the controlled condition.

© PMI, NTPC 100

DEVIATION The difference between the measured value and desired value

of the controlled condition.

AUTOMATIC CONTROLLER The item in a control system which compares the desired and

the measured values and operates in such a way as to reduce

the deviation.

MEASURING UNIT A unit which gives a signal representing the controlled

condition.

CORRECTING UNIT A unit which receives a signal from the controller to change the

control condition.

OPEN LOOP CONTROL SYSTEM A control system without monitoring feedback.

CLOSED LOOP CONTROL A control system possessing monitoring feedback, the

SYSTEM deviation signal formed as a result of this feedback being used

to control the action of the correcting element in such a way as

to tend to reduce the deviation of zero.

CLOSED LOOP CONTROL

The most common type of control system in use is the Closed Loop Control System. Fig. 29 shows

© PMI, NTPC 101

a block diagram of a closed loop control system. The controlled condition of the plant (e.g.

pressure, level, flow) is measured by the measuring unit and sends a signal to the controller of the

measured value (M.V) the controller receives a second signal which is the desired Value (D.V.) for

the controlled condition. The controller compares the desired and measured values and if a

deviation exists sends a signal to the correcting unit (e.g. Power cylinder, Control Valve) to move it

in such a direction so as to reduce the deviation.

The amount the correcting unit moves and the direction in which it travels will depend on the

magnitude and direction of the deviation.

LARGE POSITIVE M.V. - D.V. = DEVIATION - or or

SMALL NEGATIVE MAGNITUDE DIRECTION

As a closed loop control system is continuously monitoring the results of its actions by comparing

the desired and measured values the system will reduce the deviation to zero.

OPEN LOOP CONTROL

Open loop Control systems are very seldom used by them but are used in conjunction with closed

loop control systems to improve the quality of control.

Fig. 30

© PMI, NTPC 102

Fig.30 shows a block diagram of a closed loop control system to control the temperature of Air in

building. The indoor temperature is measured and compared with the desired value of temperature,

and any deviation will cause more or less fuel Oil to be burnt. The controller will see the result of its

action and adjust the fuel flow until there is no deviation. If the temperature outside the building

suddenly falls no change in temperature will occur inside the building immediately due to the wall

insulation. Eventually the inside temperature will fall and be detected by the indoor temperature

detector. The closed loop control system will eventually adjust the fuel oil flow until no deviation

exists. In other words the controlled condition must deviate late from the desired value before

correcting action can be initiated.

Fig.31 shows a block diagram of an open loop control system to control the temperature of air in a

building. The outdoor temperature is measured and compared with the desired value of

temperature, and any deviation will cause more or less fuel to be burnt. The controller will not see

the results of its actions but will supply more or less fuel depending on the magnitude and direction

of the deviation. If the temperature outside the building suddenly falls the outdoor temperature

detector will detect this immediately, and the controller will immediately increase the fuel oil flow

and therefore inside temperature.

The advantage of the open loop control system over the closed loop control system is that

corrective action can be taken as soon as the outside temperature falls. The disadvantage is that it

© PMI, NTPC 103

does not see the results of its actions and variations in inside temperature will occur due to boiler

efficiency or amount of ventilation.

Fig-32 shows a block diagram of a combined open and closed loop control system (disturbance

feedback system. In this system the closed loop control system is the main loop and will control the

inside temperature with no deviation. If the outside temperature suddenly falls the open loop system

will detect the fall in temperature and increase se the fuel oil input. By using both types of control

system together we can make use of the: advantages of both systems and improve the quality of

control.

PLANT LAGS A control, loop may be considered in three parts:

I. The plant which consists of the correcting element, the process and the detecting element.

2. The automatic controller, which consists of the measuring element and the controlling unit.

3. The interconnections between the plant and the controller.

As the plant plays such a vital part in the behavior of a control system, the nature of a plant will first

be considered.

© PMI, NTPC 104

MEASUREMENT LAG

Accurate measurement is essential for accurate control. In general, a controller makes greater

demands upon the measuring unit than does a recorder or indicator.

Consider the measurement of temperature. Before a temperature detecting element can give a

signal which accurately represents the process temperature, it is necessary for the temperature

element to be in thermal equilibrium with the process. Suppose the temperature - detecting element

is the bulb of a mercury - in - steel thermometer and that the temperature of the process rise. In

order to raise the temperature of the bulb to that of the process it is necessary for the bulb and the

mercury to, receive a definite amount of heat; the magnitude of the quantity of heat will depend

upon the thermal capacity of tire bulb and its contents, i.e. it will depend, upon the sum of products

of mass and specific heat of the components of the temperature-detecting element. The time taken

for a bulb of large thermal capacity to reach equilibrium with the process will be longer than the time

taken for a bulb of smaller thermal capacity under the same circumstances.

In addition, the time required for the bulb to reach equilibrium will depend upon the rate at which

heat transferred to the bulb; i.e. among other factors, it will depend upon:

1. The thermal conductivity of the bulb material and the medium, which surrounds the bulb.

2. The heat capacity of the fluid which comes into contact with the bulb every second, i.e. upon

the product of the velocity, the density, and the specific heat of the fluid contact with the

bulb. In this connection it is important to consider the roughness of the bulb. A rough bulb

surface tends to retain an unchanging film of fluid in contact with itself and so reduces the

rate at which the bulb receives the heat. A high velocity of liquid past the bulb will tend to

break up this film, however, so that stirring a liquid is often helpful.

© PMI, NTPC 106

3. The ratio of the surface area to the mass of the bulb, as the greater the surface area the

less the amount of material to be heated by conduction.

The time may be regarded as depending upon the resistance to transfer of heat to the bulb.

Using a simple electrical analogy, the system is similar to the circuit illustrated in Fig.34 (a1). The

time taken for the plate of a condenser to reach the same, potential as the terminal of a battery to

which it is connected will depend upon the capacity of the condenser and the resistance of the wire

connecting it to the battery terminals. In a similar manner, the time taken for the bulb to attain

equilibrium may be regarded as depending upon the capacity and resistance of the system.

If the temperature-detecting element is protected by a sheath or thermo-well the situation is further

complicated. Heat must now be given to the well to raise its temperature, and the rate at which its

temperature rises will be inversely proportional to its thermal capacity. Heat must then be

transferred from the well to the bulb, introducing a further resistance and capacity. Again using the

electrical analogy the system may be represented by Fig.34 (a2).

In order to keep the time lag of the detecting element to a minimum, the thermo well should be

made of material having the highest thermal conductivity, the lowest specific heat; it must be

smooth have a large surface area per unit mass of bulb and be placed at the point of highest

velocity in order to make R1 as small as possible; and the smallest possible thermal capacity, to

make C1 as small as possible. The space between the well and the bulb should be as small as

possible, and when a space does exist this should be filled with a medium having a good thermal

conductivity in order to make R small, and finally the thermal capacity of the detecting element

should be small in order to make C2 small.

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When a detecting element is subjected to a step change, the time lag (T sec) is taken to be the time

required for the detecting element to change by 63.2 per cent of the change, which has taken place

in the process, Fig.35. If the controlled condition is changing at a constant rate, and the detecting

element has a time lag of T sec, at any moment it will have a temperature that represents the

condition of the process at a time T Sec. before Fig.35 (b).

PROCESS LAGS Process lags will be illustrated by consideration of actual examples of simple processes having

lags. Consider the simple plant illustrated in Fig.34 (d1) in which water is being heated by passing

through a tank containing a heating coil through which steam is passed.

The rate of rise of temperature of the water will depend upon the thermal capacity of the tank and

its contents, and upon the rate of transfer of heat to the water. The lag in this system will be similar

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to the measurement lag of the unprotected mercury in steel bulb already described. The electrical

analogy is still applicable, and the rate at which the system approaches its equilibrium temperature

will depend upon the capacity and the resistance of the system, the rate increasing with decrease of

capacity or resistance.

The electric current flowing on to the plates of the condenser depends upon the potential difference

between the battery terminal and the condenser plate, so that the rate at which the potential of the

condenser plate changes is at maximum when the plate is first connected to the battery terminals,

and decreases as the potential of the plate approaches that of the terminals. In the same way, the

rate at which the condition of the process changes is at maximum when the corrective action is first

applied and. decreases as the controlled condition approaches its equilibrium state.

TRANSFER LAGS If the process liquid is heated indirectly by causing the steam to heat some transfer medium

contained in a tank inside the water tank as shown in Fig.34 (d2), the system is analogous of the

protected thermometer bulb and has two capacities with a resistance between them. The steam

must first heat the content of the inner tank, and the heat must then, be conducted through the inner

tank to the contents of the outer tank so that there will be a definite time lag before the temperature

of the liquid in the outer tank begins to rise. Owing to the time taken for the heat to be 'transferred'

to the outer tank, the process will also reach its maximum rate of temperature rise more slowly and

the process is said to have a 'transfer' lag.

DISTANCE/VELOCITY LAG

Distance/velocity lag is defined as the time interval between an alteration in the value of a signal

and its manifestation unchanged at a later part of the system, arising solely from the finite speed of

propagation of the signal.

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When applied to plant, distance/velocity lag represents the delay that occurs between the change in

process material at the correcting element and the arrival of this changed material at the detecting

element. For example, if a fluid is fleeing at a velocity v ft/sec. along a pipe, as shown in Fig.36, arid

its temperature is raised by a heater; a time equal to d/v sec will elapse before the heated fluid

reaches the detecting element at a distance d ft away.

TYPES OF CONTROL ACTIONS

DISCONTINUOUS ACTIONS

Two Step Actions

The output has two positions e.g. on-off or high-low or forward-reverse. If the deviation is positive

the output is one.

Value; if negative it is the other. This system is widely used in simple controllers, e.g. temperature

control by immersion heater and thermostat.

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Two Step Action with Overlap (Fig. 38)

If two step action causes frequent changeover of the correcting unit, excessive wear may take

place. This can bet reduced by introducing an overlap. For instance, a temperature controller might

switch on the power supply when the water temperature has dropped to 78oC but not switch it off

again until it has risen to 820, controlling nominally at 800, but with a 40 overlap. In practice all two

step actions have an overlap.

Multi step Action (Fig. 39)

This is similar to two-step except that the controller output has several positions. An example is the

automatic control of voltage by means of a tap-changer on a transformer.

Floating Action (Fig. 40)

The controller output changes when the deviation changes sign and continues to change at a

steady rate until the deviation again changes sign. This type of action is seldom used nowadays,

but an example is a valve operated by a motor, which in turn is controlled by a reversing switch.

The switch will change over when the deviation changes sign.

Two step, multi step and floating action are cheap forms of control and are used where some

variation of the controlled condition can be tolerated. On main power station plant loops hunting,

sustained oscillation of the controlled condition, Cannot be tolerated. Other forms of control must be

'used and these are referred to as continuous control actions.

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FIG 40 SINGLE-SPEED FLOATING ACTION

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CONTINUOUS ACTIONS

Proportional Action The action of a controller whose output changes by an amount that is proportional to the deviation.

The amount by which the output changes for a fixed deviation is adjustable so that the controller

response can be adjusted to suit the particular control loop. This adjustment is referred to as

proportional band.

Proportional wand (P.B.)

The change in deviation required causing the output to change from one extreme to the other.

To explain these actions it is necessary to look at a practical example of a typical controller and

control loop. A typical pneumatic controller will receive two inputs:

1. Desired Value

This is normally a red pointer which can be positioned at any point ran the chart or scale of

the instrument containing the controller. It also applies an input to the controller as the

desired value.

2. Measured Value This is normally a black pointer or pen, which is positioned on the scale or chart and

indicates the measured value of the controlled condition. It also applies an input to the

controller as the measured value.

A typical pneumatic controller will give an output that will vary between 3 p.s.i.g. and 15 p.s.i.g. (0.2

to 1 Bar) if we consider a proportional only controller and there is no difference between the desired

and measured values (zero deviation) it is normally arranged that the output pressure is 9 p.s.i.g.

which is the mid point of the 3 - 15 p.s.i.g. output range.

Depending on the control loop the controller can be adjusted to be either direct or reverse active.

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Direct Acting If the measured value increases the controller output also increases.

Reverse Acting If the measured value increases the controller output decreases.

Fig.41 shows the scale of an instrument range 0 -100% and the desired value pointer is set to 50%.

If the measured value pointer is also at 50%, as stated previously the output will be 9 p.s.i.g. If the

controller is of the direct acting type an increase in measured value above the desired value will

cause the controller output to increase. We can adjust the amount that the output changes for a

given deviation by adjusting the proportional band.

If the proportional band setting on the controller is 100% then a 50% deviation above the desired

value will cause the output to change from 9 to 15 p.s.i.g. A 50% deviation below the desired value

will cause the output to change from 9 - 3 p.s.i.g. The controller output has changed from one

extreme (3 p.s.i.g.) to the other (15 p.s.i.g.) for a total deviation of 100$ (-50% to +50%).

If the proportional band setting is changed to 20% then a 10% deviation either side of the desired

value will cause the controller output to change from one extreme (3 p.s.i.g.) to the other (15

p.s.i.g.).

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As can be seen from Fig. 41 the output will always be 9 p.s.i.g. with zero deviation irrespective of

proportional band setting.

Proportional Band and Gain

When dealing with electronic controllers it is more, convenient to consider the proportional band

adjustment in terms of gain.

GAIN = 100

P. B.

P.B. = 100

GAIN

OFFSET

Offset is the name given to a sustained deviation between desired and measured values. Offset will

occur on a control system controlled by 3 proportional only controller following a-load change on the

control system.

Let us consider the control system shown in Fig. 42. The graph (solid line) shows the relationship

between percentage flow rate and controller output. The control valve is fully open at 15 p.s.i.g. and

shut at 3 p.s.i.g. For an increase in measured value we required the value to close, therefore the

controller would be of the reverse acting type. Let us assume that the proportional band is 100%

and the measured and desired values coincident at 50% flow. As stated previously with zero

deviation the controller output will be 9 p.s.i.g. which, in this loop, will give 50% flow as desired. As

long as the relationship between flow and controller output remains as shown in Fig. 42 the loop will

control with zero deviation.

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Let us, now consider a load change in the form of an increase in pressure at the inlet of the control

value. This will obviously increase in the flow through the valve for the same value opening. The

dotted line shows the new relationship between percentage flow rate and controller output. At the

instant that the pressure changes the measured value of flow would rise from 50% to 60%. This

would apply a deviation to the controller of 10%. If the controller P.H. is 100% then the controller

output would fall by 10% (Reverse acting controller) to 7.8 p.s.i.g. If this output were maintained it

can be seen from the dotted line that the measured value would fall to 48%. As the flow falls from

60% to 48% however, the deviation applied to the controller will decrease and the controller output

will rise. In the example shown the flow would settle out at 54% giving an offset of 4% between the

desired and measured values. An offset has occurred due to a load change.

The amount of offset can be reduced by decreasing the proportional band. If the proportional band

is decreased from 100% to 50% the offset in the above example would be reduced to 2%. There is

however a limit to the lowest value of proportional band that can be used for a particular loop. This

limit is when the loopy becomes so sensitive that continuous oscillations of the measured value

occur.

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Proportional action therefore gives us a continuous control action which will not result in continuous

oscillations of the controlled condition if used correctly. The problem with purely proportional action

is that offset will occur if the load on the system changes. On minor loops this offset can be

overcome by adjusting the desired value pointer until the measured value comes to the required

value of controlled condition.

On main Power Station loops this manual adjustment of the desired value is not acceptable and

further control actions are required. A proportional only controller is often referred to as a single

term controller.

Integral Action

The action of a controller whose output changes at a rate proportional to the deviation.

The rate at which the output changes for a fixed deviation is adjustable to suit the particular control

loop. This adjustment is referred to as the Integral Action Time.

Integral Action Time (I.A.T.)

The time taken for the integral action to change the output by the same amount as the proportional

action.

Integral action is used in conjunction with proportional, action to remove offset. As we have seen

proportional action by itself gives rise to offset due to load changes. Using integral action, as long

as a deviation exists (Offset) the controller will cause its output to change at a rate, proportional to

the deviation, until it is removed.

Let us consider the output of a proportional plus integral controller for a constant deviation. A

constant deviation will be considered, as it is much easier to see the control actions that take place.

Fig.43 shows the changes in output for a proportional plus integral controller when a constant

deviation is applied. At time T1 the deviation is applied and the controller output signal will change

instantly by an amount depending on the proportional band setting and the magnitude of the

deviation. No further change in output will occur due to proportional action. The integral action will

also see the deviation and cause the output to change at a rate proportional to the deviation.

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As long as the deviation remains the output will continue to rise due to integral action. At time T2 in

Fig. 43 the change in output due to integral action is equal to the change in output due to

proportional action. The time period T1 to T2 is the integral action time for the controller. If the initial

deviation is removed at time T3 then the output would drop, due to proportional action, by the same

amount as it increased at time T1. The controller output would now be higher than it was initially

due to the integral action and will remain at that value as long as the deviation stays at zero. By

using proportional and integral action together any offset that tends to occur due to load changes

will be removed by the integral action.

Example

A controller has a proportional band setting of 50% and an integral action time of 2 minutes. If a

deviation of 10% is applied how long will it take the output to rise by 40%

Gain = 100 = 100 = 2

P.B. 50

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For a 10% deviation the output would change by 10% x 2 = 20% due to proportional action

instantaneously. The output will then increase by 20% due to integral action in 2 minutes. The

output will therefore change by 40% in 2 minutes.

A proportional plus integral action controller is often referred to as a two-term controller.

INTEGRAL SATURATION

In a process where large deviations of measured value from desired value occur due to large load

changes, it is possible for a- proportional plus integral action controller to integrate to one extreme

or other of its output range.

If we consider a pneumatic 3 -15 p.s.i.g. output controller then its supply pressure would be about

20 p.s.i.g. The two possible extremes of output pressure would not be 3 - 15 p.s.i.g. but 0 - 20

p.s.i.g. This means that no control action would occur below 3 p.s.i.g. or above 15 p.s.i.g. (the

correcting element will not respond to pressure outside the 3 - 15 p.s.i.g. range). As the control

system reduces the deviation after the load change no response will occur from the controller until

the measured value crosses the desired value. When this occurs the controller output will start to

increase from 0 p.s.i.g. or decrease from 20 p.s.i.g. due to proportional and integral action. The

correcting element however will not respond to the controller output signal until it is within the 3 - 15

p.s.i.g. control range. This will result in a large overshoot of the measured value before correct

control at the desired value is obtained.

To prevent integral saturation occurring special units can be fitted to the outputs of pneumatic

controllers to prevent the output rising above 15 p.s.i.g. or below 3 p.s.i.g. these units are known as

Maximum and Minimum Integral Desaturators.

Most electronic controllers have integral desaturaters fitted ac a standard feature.

Derivative Action

The action of a controller whose output changes by an amount, which is proportional to the rate of

change of deviation.

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The amount by which the output changes for a fixed rate of change of deviation is adjustable to suit

the particular control loop. This adjustment is referred to as the derivative action time (D.A.T.)

Derivation Action Time (D.A.T.)

The time taken for the proportional action to reproduce the same change in output as derivative

action.

Derivative action is used in conjunction with proportional and integral action to overcome the

problems of large time delays in a process. As we have seen proportional and integral action

together will provide good control with no offset. If however there are large time delays between the

actual measured values of the process being detected by the control system (e.g. distance velocity

lag) then this can give rise to instability in the control system as the controller is never in phase with

the changes occurring in the process.

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Let us consider the output of a proportional plus derivative controller for a constant rate of change

of deviation. Fig. 44 shows the change in output for a proportional plus derivative controller when a

constant rate of change of deviation is applied. At time T1 the actual rate of change of deviation

commences but is not seen by the control system until after the process time lag. As soon as the

rate of change of deviation is seen by the controller at time T2 the output will change by an amount

proportional to the rate of change of deviation due to derivative action. (At time T2 no actual

magnitude of deviation exists so no proportional action can be generated). Between time T2 and T3

the magnitude of the deviation increases and proportional action gives an output, which increases

as the deviation, increases. At time T3 in Fig. 44 the change in output due to proportional action is

equal to the change in output due to derivative action. The time period T2 to T3 is the derivative

action time for the controller.

The effect of the derivative action is to give a step change to the controller output at time T2. By

extending the output graph backwards from this step change at T2 to T1 it can be seen that the

graph cuts the controller output graph at point T1, the start of the actual deviation. Derivative action

therefore brings the controller back in phase with changes occurring in the process. Derivative

action time is adjustable so that we can achieve exactly the right amount of step change in out put

to bring us back in phase with the process. Too long a derivative action time will result in too high a

step change in output, too short a derivative action time will result in too low a step change in

output.

Derivative action is only used on control systems where very long time lags are encountered. A

typical power station loop in which derivative action would be used is the superheat temperature

control loop, where time lags can vary from 2 to 3 minutes.

A proportional plus integral plus derivative controller is often referred to as a three term controller.

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The response of proportional only, proportional plus integral and proportional plus integral plus

derivative controllers to the same deviation is shown in Fig. 45.

PROPORTIONAL PLUS INTEGRAL ACTION

Fig. 46 shows a proportional plus integral action controller.

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The proportional action will be generated by the proportional bellows as previously described. For

integral action a second bellows, integral bellows, is added which is arranged to oppose the

proportional bellows (positive feedback) the controller output pressure is applied to the integral

bellows via a needle valve. The integral bellows has capacity and the needle valve will offer

resistance to air flow so that together they form an RC network. The resistance to air flow through

the needle valve can be adjusted to give control over the time constant.

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With reference to Fig. 47(A) let us look at the operation of this controller for .a step change in

deviation. The integral value is assumed to be partially closed, pressure in both bellows 9 p.s.i.g.

and zero deviation. A step change of deviation is applied thaw causes the controller output pressure

to increase from 9 - 12 p.s.i.g. The proportional bellows will immediately increase from 9 - 12 p.s.i.g.

and apply negative feedback to the flapper. The integral bellows at the same instant will still be at 9

p.s.i.g. due to the needle value Fig. 47(B). As the pressure in the integral bellows increases from 9

- 10 p.s.i.g. This will cause the flapper to move closer to the nozzle increasing the output and

proportional bellows pressure increase to 13 p.s.i.g. This means the integral bellows still lags the

proportional bellows pressure by 3 p.s.i.g. In the same way as the integral bellows increases from

10-11 p.s.i.g. The output and proportional bellows pressure increase to 14 p.s.i.g. Fig 47(C).

If the deviation is halved, Fig. 47(D), then the output and proportional bellows will drop to 12.5

p.s.i.g. whilst the integral bellows will remain at 11 p.s.i.g. (a difference between proportional and

integral bellows of 1.5 p.s.i.g.). If the deviation had been removed completely, Fig. 47(E), then the

output and proportional bellows would drop to 11 p.s.i.g. which is the same pressure as the integral

bellows. This means that no further change in output pressure would occur as both bellows are

balanced at 11 p.s.i.g. (pressures cancel out as in Fig. 47A) and zero deviation is applied to the

flapper.

From the above examples it can be seen that for zero deviation any pressure between 3 and 15

p.s.i.g. can exist at the controller output for zero deviation. For a purely proportional controller only

one output pressure can exist for zero deviation and on a 3 - 15 p.s.i.g. system this would be 9

p.s.i.g.

With a proportional plus integral action controller therefore if a deviation exists between D.V. and

M.V. then the controller output would integrate towards 3 or 15 p.s.i.g. until the deviation was

removed. At zero deviation the output pressure would then remain constant (assuming no load

changes) at some pressure between 3 and 15 p.s.i.g. the integral action time is adjusted by altering

the opening of the integral needle value.

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PROPORTIONAL PLUS DERIVATIVE ACTION

Fig. 48 shows a proportional plus derivation action controller. The proportional action will again be

generated by the proportional bellows. To produce derivative action a needle valve is fitted between

the controller output and the proportional bellows. As with integral action the capacity of the bellows

and the value of restriction of the needle valve form a variable R.C. time constant. Let us look at the

operation of this controller for a rate of change of deviation. The derivative value is assumed to be

partially closed, controller output pressure and proportional bellows pressure 9 p.s.i.g. and zero

deviation. If a rate of change of deviation now occurs causing the flapper to move towards the

nozzle then the controller output pressure will also start to increase. Due to the derivative restrictor

the proportional bellows will not receive the output pressure immediately and negative feedback to

the flapper will be delayed. This will cause a much greater change in output pressure than would

have occurred with purely proportional action. After the initial change in output due to the restrictor,

air will pass through into the proportional bellows and negative feedback applied. For a constant

rate of change of deviation a constant pressure drop will exist across the derivative needle valve.

As soon as the rate of change of deviation ceases then the pressure each side of the needle valve

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will equalize. The effect of derivative action is therefore to give a step change in output proportional

to the rate of change of deviation. The deviate action time is adjusted by altering the opening of the

derivative needle valve.

A.M.T.S. STATIONS Fig. 49 The Auto-manual-test-service station is a regulating, and switching system with four positions to

allow manual control whilst the controller is under maintenance:

1. Automatic The operator leaves the AMTS station on automatic and the plant is

controlled automatically. The controller output pressure is fed directly

to the correcting unit.

2. Manual The operator can switch to manual if he wishes to control the plant by

hand. The correcting unit is now fed from the manual regulator as the

controller output is disconnected. In order to prevent integral

saturation, the integral chamber of the controller is not shut OFF or

vented but receives the output signal of the manual regulator.

3. Test The mechanic can switch to test enabling him to test and adjust the

controller (with air supplies available) whilst the operator still controls

the plant manually. The only difference from the manual position is

that the integral chamber now is reconnected to the controller output

instead of to the manual regulator.

4. Service The mechanic can switch to service cutting off air supplies to the

controller whilst he overhauls it. After switching to service he should

remove the knob to prevent anyone restoring air supplies whilst he

has pressure connections dismantled. The operator can still control

the plant manually.

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A catch behind the panel prevents the operator from selecting positions 3 and 4.

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Bump less Transfer

When transferring from auto to manual, or back again, the manual regulator should be operated to

make the auto and manual output pressures equal. (If a differential pressure gauge is fitted, this

should read zero). Then when changeover is made, there will be no disturbance to the plant.

Plug in Controllers

A.M.T.S. stations are unnecessary with some modern pneumatic controllers, where the controller to

be serviced can be unplugged and replaced by another very quickly whilst on manual control. The

unit unplugged is then taken back to the workshop for service.

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Furnace Draft Control (Fig. 50)

1. The furnace draft shall be maintained by regulating the position of the inlet control vanes of

ID Fans. The speed of each ID Fan shall be suitably controlled so that the inlet-vanes are

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kept in the optimum range for good response capability and at the same time pressure drop

across the control vanes is also kept low. This shall be accomplished by regulating the

speed of individual ID Fans by hydraulic coupling scoop tube control. The furnace draft

control system shall meet all requirements of NFPA code no. 85G and other applicable

codes and standards.

2. The furnace draft shall be measured by three redundant transmitters and median selectors,

deviation monitoring circuits etc. The measured value shall be fed to suitable limit value

monitors, the output from which shall be voted with furnace pressure switch output and shall

initiate blocking action on FD Fan blade pitch control and ID Fan controls.

3. The furnace pressure set point shall be adjusted to vary within safe operating limits during

the commissioning period and the operator shall not be able to change the set point beyond

these limits. The measured value and desired value of furnace draft shall be compared in a

proportional, integral action controller and the controller output shall be used to position the

inlet vanes of operating ID Fans. A feed forward signal corresponding to unit load demand

shall be used to maintain proper furnace draft during transient conditions.

4. Fan balancing network using controller output and position feedback signal from control

drives shall regulate the inlet vanes of all operating fans in synchronism or with preset

value of biasing depending on the setting of the biasing station.

5. The speed of individual ID Fans shall be controlled to maintain the ID Fans inlet vanes in

optimum control range with minimum pressure loss. ID Fan inlet vane position shall be

measured and compared with a manually adjustable set point. The error signal shall be

passed through a dead band unit which shall allow excursions of inlet vane within

permissible limits and then through a proportional plus integral action controller. The

controller output shall be used for positioning of hydraulic coupling scoop tube for individual

ID Fans. A signal corresponding to boiler load index shall be used as the feed forward signal

for improving the transient response.

6. Uniform dynamic response of system shall be maintained over the entire load range by

automatically compensating the appropriate control loop gains depending upon the no. of ID

Fans in service and the output of ID Fans in manual operation.

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7. Directional blocking of fan controls shall be provided both in automatic and manual modes to

prevent further aggravation of dangerous conditions when the furnace draft is either too low

or too high. When the furnace draft is too low further increase of ID Fan capacity or

decrease of FD Fan capacity shall be blocked. Similarly when the furnace draft is very high,

further reduction of ID Fan capacity or increase of FD Fan capacity shall be blocked. This

interlock shall be operative only after the furnace draft goes out of present bands

(approximately by ± 75 mm) and shall be operated by two out of three furnace switches.

8. When the furnace pressure exceeds a pre-determined high-high value, the furnace draft

control system shall provide a cutback signal for reduction of FD Fan output and

corresponding reduction in fuel firing rate.

9. Provision shall be made for automatic tripping of one FD Fan, when furnace pressure

exceeds a preset value approximately by +200 mm wcl and for tripping of one ID Fan, when

furnace draft is- less than a preset value approximately by -200 mm wcl. This shall also be

operated by 2 out of 3 logics.

10. On MFT, the ID Fan inlet vanes and. scoop tubes for hydraulic couplings shall be driven to

pre-selected positions so as to contain the pressure excursions within safe limits. After an

adjustable time delay, the control drives shall again be released for automatic control.

11. Fan limit controls shall be provided.

12. Implosion protection control shall be provided.

13. Over-riding control actions for opening, closing and blocking of position change signals shall

be provided both in Auto and Manual modes for each fan control system for inlet vanes and

speed control. These impulses shall be received from ID Fan logics and furnace draft control

logics described above.

14. The following Hand/Auto stations shall be provided:

a. Furnace draft master Hand/Auto station with provision for manual adjustment of set

point.

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b. ID Fan A vane control Hand/Auto station with provision for biasing.

c. ID Fan B vane control Hand/Auto station with provision for biasing.

d. ID Fan C vane control Hand/Auto station with provision for biasing.

e. ID Fan A/B/C speed control Hand/Auto station with provisions for manual adjustment

of set points (Total = Three Hand/Auto station.

Final Steam Pressure Control (Fig. 51)

This is possibly the most important loop in the control scheme as it is the first to respond to any

change of load on the boiler. Its function, in simple terms, is to regulate the fuel input to suit the load

so maintaining the super heater outlet pressure at the required value.

Regulation of the fuel is achieved by controlling the speed of the raw coal feeder thus varying the

coal feeding to the mills. In some design of the mills the control is affected by varying the primary air

flow thought the mills. As the number of mills in service will vary and it is desirable that all mills in

service be equally loaded. It is not possible to use a simple loop with only one controller controlling

all six Primary Air damper or Raw coal feeder speed variator. The actual control loop employed is

as follows.

The pressures at the WO boiler outlets are measured by transmitters PTI-2 and their average

computed by XCI. This average forms the measured value of master pressure controller PCI. The

output from PCI resets the desired value of the total Primary Air controller (Fuel flow controller) FCI,

the measured value for which is obtained by summating at - XC 8 the individual primary air flows

read by transmitters FT 1-6 or feeder speed as the case may be. The resultant output signal from

FCI resets the desired value of the individual Primary Air (R.C. feeder speed) controllers FC 2-7.

Load distributor units XC 2-7 are installed between the total fuel flow controller (P.A. floor or feeder

speed) FCI and the individual controller FC 2-7. These enable the individual mill loads to be equal

or biased to proportion the load as required. During normal operation over ride unit XC 9 will

provide a straight through path for the output signal from the master pressure controller PCI and it

will only operate when there is a deficiency of air.

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Combustion Control (Fig. 52)

Combustion control consists basically of ensuring that the correct amount of air is supplied to

completely burn all the fuel being used. Insufficient air results in unburnt fuel while excess, air

increases the quantity of waste heat passing to the stack.

As there is no effective way available of accurately monitoring the fuel input either the primary

airflow or the feeder speed is used as a measure of fuel used. The main disadvantage of this

system is that tile ratio of fuel to primary air (feeder speed) is in itself variable and depends on many

factors such as efficiency of milling plant, percentage ash in fuel and efficiency of mill control

scheme. It is however relatively fast and can be trimmed by more sophisticated controls which are

themselves too slow to use along. They are steam/air ratio, and percentage oxygen in flue gas

system.

The steam/air ratio method is based on the fact that boiler efficiency at loads likely to be carried on

auto control remains effectively constant, therefore heat required is proportional is fuel required

then air flow is proportional to steam flow. Ash content in the coal does not affect this method which

is the ratio of hydrogen to carbon in the fuel remains constant, is reasonably accurate.

© PMI, NTPC 136

The oxygen in flue gas method is perhaps the most accurate form of control but it too has

disadvantages. It is slow due to the time taken to process the gas sample and it is difficult to obtain

a representative gas sample especially from furnaces of the size used for 210 MW and 500 MW

units.

The system used to trim the coarse control can be selected by the operator from the two mentioned

above.

© PMI, NTPC 137

Feed Water Control

1. The feed water control system shall comprise of the following three sub-loops:

a. Single element drum level control.

b. Three element drum level control.

c. D.P. across feed regulating valve control.

2. The above three sub loops shall act on the following final control elements so as to maintain

the drum level and D.P. across the feed regulating valves at the present values.

a. 2x50% capacity turbine driven boiler feed pumps (BFPT) each provided with electro-

hydraulic control system for variation of pump speed.

b. 1x50% capacity motor driven boiler feed pump (MBFP) provided with hydraulic

coupling with scoop tube control for variation of pump speed.

c. One low load control valve with approximately 30% capacity, for drum level control

during start up and under low load conditions.

d. 3x50% capacity feed control valves for drum level control above 30% MCR. Only two

out of these three control valves will be operative and the third will act as standby.

(Each of the three boilers feed pumps shall be able to continuously sustain 60% load

when only one feed pump is in service).

3. Two redundant drum level transmitters shall be provided for control purposes and connected

to independent pairs of tapings on either side of the boiler drum. Density compensation shall

be provided by using two separate pressure transmitter and redundant compensating

circuits to account for change in density of water in the boiler drum.

© PMI, NTPC 138

Comparison circuits, selector switches, bypass switches and alarms etc. shall be provided

for drum level and drum pressure signals. Provision shall be made for selecting any one of

the drum level signals or their average for control purposes.

4. Total steam flow signal shall be computed by adding turbine first stage pressure and steam

flow to H.P. Bypass station. Three independent transmitter, median selector and deviation

monitoring circuit etc. shall be provided for first stage pressure signal.

5. Total feed water flow signal shall be computed by adding feed water flow at economizer inlet

and super heater spray water flow. Three independent transmitters, median selector,

deviation monitoring circuits etc. shall be provided for feed water flow at economizer inlet.

The above signal shall be separately temperature compensated and square root

extracted.

6. Single Element Control During start up, and at low-loads, a single element controller using durm level signal shall be

used for regulating feed water flow by modulating low load feed control valve. The durm

level signal shall be compared with a manually set desired value signal in a PID controller.

The set point for single element controller shall be normally kept lower than the set point for

three element controllers so as to avoid interaction between two sub-loops.

7. Three Element Drum Level Control Three element drum level control system using steam flow, feed water flow and drum level

signals shall be used for regulating feed water flow from 25-30% to 100% MCR. This system

shall be configured in cascade design. The output of drum level controller (PID) shall be

added to steam flow signal to provide the set value for feed water controller (PI). The

feedback signal from total feed water flow (S. No. 5 above) shall be compared with this set

value and the controller output shall be used for regulating the 50% capacity feed regulating

valves or shall provide the desired value signal for individual speed controller of turbine

driven boiler feed pumps.

8. D.P. Across Feed Regulating Valve Control Differential pressure across feed regulating valves shall be measured by two redundant

transmitters and comparison networks etc. shall be provided. This measured value signal

© PMI, NTPC 139

shall be compared with the operator set desired value (set point) in a proportional and

integral action controller which will generate the desired speed signal for individual speed

controllers for motor driven or turbine driven boiler feed pumps. The speed of boiler feed

pumps shall be controlled by using either this signal or the signal from three element drum

level controller.

9. Individual speed control loops shall be provided for each Boiler feed pump which will amount

for different types of speed control mechanisms for motor driven and turbine driven BFPs,

their widely varying dynamic response characteristics and non-linearity of hydraulic

couplings and turbine driven BFPs.

10. The speed controller of each BFP shall compare the desired speed signal from controllers at

S.No. 7 or 8 above based on programme control with the actual speed feed back signal from

the respective BFP. The output of this controller shall regulate the speed control mechanism

of the concerned BFP to equalize the desired and actual speed signals.

11. Provision shall be made for biasing the BFPs depending upon their load carrying capacity.

BFP speed control circuits shall enable operation of both operating BFPs in synchronism or

with the desired degree of biasing depending upon the setting of the respective biasing

station.

12. Uniform dynamic response shall be ensured by automatically changing the control system

gain to account for the number and type of boiler feed pumps in service.

13. The control system design shall make necessary provision for avoiding mal-operation of the

feed water control system due to swelling, shrinkage of drum level and other system upsets

during the transient conditions.

14. Programmed Change over of Control Regimes

a. The control system design shall make adequate provision for satisfactory transfer of

control signal from single element control to three element control, change over from

low load to full load control valves, change over from motor driven pump to the

turbine driven BFP and vice-versa without any system upset. All potential

© PMI, NTPC 140

disturbances in feed water supply due to simultaneous and opposed regulation of

two types of pumps during transfer or due to any other reason shall be avoided by

providing suitable hardwares and system design.

b. The change over from one operating regime to the other shall be initiated either

automatically or manually and all such changes shall be effected without causing any

system upset.

c. From start up to about 25% MCR, the drum level shall be controlled by single

element controller acting on low load control valve. The set point of this controller

shall be lower than the set point of three element controller to avoid interaction

'between the respective loops. During this period the speed of start up BFP shall be

determined by the DP across feed regulating valve. The, DP controller shall be

programme biased during start up so as to ensure an adequate flow through the low

feed regulating valve. This will counter the effect of starting of the' boiler circulating

pumps, when the water may fall by several inches.

During start up, the higher drum level set point of three element controller shall be

programmed to be biased lower than the single element controller so as to keep the

50$ capacity regulating valves closed.

d. At about 25% MCR, the upstream isolating valves of the selected main feed

regulating valves will be opened and the programme bias will be removed from three

elements controller and the DP controller. Thus three elements controller will ask for

a higher drum level, causing the main feed-regulating valves to open. The higher

drum level will cause single element controller to close the low load control valves.

The removal of bias from differential pressure controller will restore the set point to

the normal required pressure drop across the feed regulating valves.

e. When the motor driven pump is in operation, a positive bias will be programmed to

the speed controller to Turbine driven BFP, thus setting the BFPT governor to

maximum setting. When sufficient steam is available, this will be admitted to the

BFPT and the turbine driven BFP will start delivering water. Due to the above

mentioned bias on BFPT speed controller, it will override the action of the MBFP

© PMI, NTPC 141

speed controller. The turbine driven BFP will therefore, progressively reduce until it

ceases to deliver feed water. At this time the MBFP will be shut down by the operator

the programme bias will be removed from BFPT sped controller. The feed water will

now be supplied by turbine driven BFP with speed control from DP controllers and

three element drum level control acting on main feed-control valves.

f. The final change involves changing over the speed control of BFPT from DP

controller, to three element controller. This change is done when only BFPTs are

running and is accomplished by the programmed action of the biasing unit B1 which

applies a positive bias to the signal going to feed regulating valves causing them to

open wide, and simultaneously reduce the signal going to the low signal selector.

Thus the speed governor setting is transferred from the pressure drop controller to

the three element controller.

g. If the turbine driven BFP does not respond to a reduction in demand, the three-

element controller would operate the feed regulating valves at the biased-up valve

and a similar action would result if the MBFP is started on emergency operation.

h. When shutting down, the above stated programme bias will be removed from the

control signal from three element controller going to feed regulating valves and the

signal going to low signal selector will restored to feed regulating valves and turbine

driven BFP speed will be controlled by DP controller.

i. At a programmed load level, MBFP will be brought into service simultaneously with a

positive bias being supplied to the MBFP speed controller, as the steam supply to

BFPT falls, the delivery of turbine driven BFP will reduce, causing the speed

controller for BFPT to be 'saturated' with the steam-admission valves in wide open

position. Simultaneously, the MBFP increases its speeds under the action of DP

control. When MBFP will increase its speeds under the action of DP control. When

BFPT ceases to delivery water, the steam valves will be closed but the feed water

control will be under three element control and main feed regulating valves.

© PMI, NTPC 142

j. At a predetermined load, the set point of three element controller will be programme

biased below the set value of single element controller. This lower set value will

cause three element controller to close the main regulating valves. At the correct

water level, the Single element controller causes the low load control valve to open.

The balance shutdown procedure for feed water control will be under the influence of

single element controller which will regulate the low load control valve.

k. The system shall permit automatic and manual operation of motor driven, turbine

driven feed pumps, and feed control valves in all possible combinations for

satisfactory control of drum level and stable operation of the Unit.

15. Interlocks shall be provided for over-riding control action to set the scoop tube of hydraulic

coupling of motor driven BFP to the minimum position for pump start up, both in automatic

and manual mode. The initiation of this action shall be from the feed pump control circuits.


a. Low load control valve Hand/Auto station.

b. High range feed water control valves Hand/Auto stations with provision for manual

biasing - Three Nos.

c. High range feed water control valve Hand/Auto station with manual adjustment of

drum level set points.

d. Boiler feed pump master Hand/Auto station with manual adjustment of set point

value of control valve differential pressure.

e. Boiler feed pump 'A'/Hand/Auto station with provision for manual biasing (Turbine

driven BFP).

f. Boiler feed pump 'B'/Hand/Auto station with provision for manual biasing (Turbine

driven BFP).

g. Boiler feed pump 'C'/Hand/Auto station (Motor driven BFP) with provision for manual

biasing.

© PMI, NTPC 143

Feed Water Control for Once Through Boiler (Refer functional diagram No. 53, 54, 55, 56)

1. The feed water control system shall proportionate the feed water flow entering the

economizer with the steam flow at boiler outlet in order to ensure correct water feeding for

the steam generation under all conditions of load.

a. 2x50% capacity turbine driven boiler feed pumps each provided with electro-

hydraulic control system for variation of pump sped.

b. 1X50% capacity motor driven boiler feed pump provided with hydraulic coupling with

scoop tube control for variation of pump speed.

c. Separate water level control system.

(Each of the three boilers feed pumps shall be able to continuously sustain 60% load

when only one feed pump is in service).

© PMI, NTPC 148

2. The separate level control system has been provided for water level control in separator

during wet separator regime of boiler operation, (i.e., when the unit load is lower than 35%.

The difference of feed water flow and steam produced gets collected in the separator and is

re-circulated through AA, AN and ANB valves.

3. Three redundant transmitters for separator outlet steam pressure and temperature shall be

provided for control purpose and connected to independent pairs of tappings on separator.

Comparison circuits, selection/bypass arrangement and alarms, etc., shall be provided for

these signals.

4. Total feedwater flow at economizer inlet shall be computed by three redundant flow

transmitters. The flow signal shall be compensated for temperature. Comparison circuit,

selection and alarms, etc shall be provided. The temperature compensated signal of SH

spray flow shall also be computed through 2 Nos. redundant transmitters.

5. Separator level Control (Single element Control) (Refer Fig. No. 56).

During start up and low loads, a single element controller using separator level signal shall

be used for regulation of feed water flow. When the unit load is less than 35%, i.e. when the

steam flow produced is lower than 35%, the feed water flow is still maintained at the

minimum value of 35% and the excess water is re-circulated through a heat exchanger and

separator level is controlled by discharging water using AA, AN and ANB valves. The control

loops uses the measurement of the separator level (pressure compensated) which is

compared with three different set points, one for each control valves AA, AN and ANB in a

split range PI controller. According to the level variation, the valves are opened in split range

in order to evacuate the excess of water due to minimum flow requirement. The control

system is provided with features to prevent mal-operation due to swelling and shrinkage.

6. Three Element Control The three element control system using steam pressure at separator outlet, the steam

temperature and also feed water flow (as a feedback signal) shall be used for regulating

feed water flow from 35% MCR to 100% MCR.

The set point of the enthalpy is computed from the saturation enthalpy (taking the pressure

at separator outlet as reference) with an offset value which varies depending on Boiler Load

© PMI, NTPC 149

Index variation. This set point is adjusted in order to maintain a ration between SH spray

water flow and feed water flow by means of a PI controller. Thus elaborated set point is then

compared in PID controller to the value of the measured enthalpy controller to the value of

the measured enthalpy computed by using temperature and pressure measurements of

steam at separator outlet. This output is further corrected by a saturation temperature

protection loop using the measurement of the temperature at the separator outlet in order to

maintain separator outlet temperature inside a preset band. Finally PID controller's output is

modified by a feed forward signal of maximum of Boiler demand through the PD+ and fuel

flow in order to ensure feed water flow when boiler load increases and to ensure feed flow

corresponding to coal flow during load decrease. This output is compared in high selector

with minimum water flow and then compared with actual feed water flow in a PI controller.

Output of the controller provides the desired speed signal for speed control systems of

individual boiler feed pumps.

7. Individual speed control loops are provided for each Boiler feed pump which account for

different types of speed control mechanisms for motor driven and turbine driven BFPs, their

widely varying dynamic response characteristics and non-linearity of hydraulic couplings and

turbine driven BFPs.

8. The speed controller of each BFP shall compare the desired speed signal from three

element feed water control system with the actual speed feed back signal from the

respective BFP. The output of this controller shall modulate the speed control mechanism of

concerned BFP to equalize the desired for and actual speed signals.

9 Provision are made for biasing the BFPs depending upon their loads carrying capacity. BFP

speed control circuits shall enable operation of both operating BFPs in synchronism or with

desired degree of biasing stations.

10. The following Hand/Auto stations shall be provided as (hardwired backup.

a. Bailer feed pump master Hand/Auto station

b. Boiler feed pump A Hand/Auto station (Turbine driven BFP)

c. Boiler feed pump B Hand/Auto station (Turbine driven BFP)

d. Boiler feed pump C Hand/Auto station (Motor driven BFP)

© PMI, NTPC 150

e. Low load control valve Hand/Auto station

f. FW/SH spray ratio controller Hand/Auto station.

The Boiler master Hand/Auto station shall be prohibited from being placed in Auto

unless there is at least one boiler feed pump in Auto.

Mill Level Control (Refer Fig. 57, 58) (For Tube Mills)

The quantity of raw coal introduced into the tube mill from the raw coal feeder depends upon the

mill level condition. Two methods are envisaged for this control.

i. Mill level control as a function of noise generated by the mill (acoustic method)

ii. Mill level control based on differential pressure measurement.

An acoustic detection device is used to monitor the noise level of the mill, which in turn depends

upon the mill loading. A microphone is suitably located outside the mill rotating body, but close to a

point where the iron balls impinge the mill body while falling. The microphone output signal is

filtered using digital filters and then fed to a microprocessor-based computer. The computed output

is fed to a PI controller which in turn adjusts the raw coal feeder speed to maintain the coal level.

In the differential pressure method, instrument air from a volume chamber is fed continuously

through the tapping on the upper and lower portion of the mill, as indicated in the scheme. Initially

when the coal level is low, the differential pressure between these tappings will be zero (minimum).

As the coal level increases, the differential pressure increases which is calibrated in terms of the

mill level.

© PMI, NTPC 152

Differential pressure control to maintain purge tank, pressure as well, as the seal air fan pressure is

envisaged. Adequate blow down arrangement are also envisaged.

The DP method is generally used for the mill level control and the acoustic method is used for

monitoring purpose.

Super heater Steam Temperature Control (Fig. 59)

1. The superheated steam temperature shall be controlled by regulating the attemperator

spray water flow to two desuperheaters located between low temperature superheater outlet

and division panel inlet. Two parallel cascaded control systems shall be provided - one for

the left side and the other for the right side desuperheater.

2. Spray water flow to each desuperheater is regulated by two control valves (one operating

and other standby). Each spray control valve is provided with a motor operated isolating

valve and a common pneumatically operated quick acting block valve is provided to isolate

the entire superheater spray control station when required.

3. The temperature at the outlet of the final superheater and desuperheaters shall be

measured by two redundant sensors and converters at each point and facility, for mismatch

monitoring etc. shall be provided.

4. The Control system shall include an adjustable ramped set point from boiler load index for

low load operation. An operator adjustable manual set point signal shall be able to over-ride

the ramped set point in order to reduce steam temperature and/or maintain temperatures

constant at desired 540oC when the unit carries normal load

© PMI, NTPC 153

5. The super heater outlet temperature shall be compared with the above set value in a PID

Controller. The output of this Controller shall be added with a feed forward signal

representing unit load and any other signal considered appropriate, to establish a set point

value for the desuperheater outlet temperature controller. This set point value shall be

compared in a second controller (PI) with the desuperheater outlet temperature. The output

of this slave controller shall be used for modulating two spray control valves for each

desuperheater.

© PMI, NTPC 154

6. Motor operated isolating valves for spray control valves shall be used for selecting the

operating stream from UCB.

7. Interlocks shall be provided both in automatic and manual mode to automatically close all

control valves o turbine trip or fuel trip and to inhibit operation of spray control valves below

an adjustable minimum load.

8. Adaptive gain control and other required features shall be provided to meet the performance

requirements for this control system within the capabilities of steam generator for full

operating regime.


a. Superheater A spray control Hand/Auto station with provision for manual adjustment

of set point.

b. Superheater B spray control Hand/Auto station with provision for manual adjustment

of set point.

© PMI, NTPC 155

6. Data Acquisition System (DAS)

INTRODUCTION

Power plant operation is a very specialized field & requires close & simultaneous monitoring of

various plant equipment like boiler, turbine, generator, feed pump etc. and associated auxiliaries to

maintain the continuous availability of the unit as well as to ensure safe & efficient operation of

these equipments. For such monitoring purposes, a lot of plant data (analog inputs) in the form of

physical measurements and status of equipment (digital inputs) are needed (around 4500).

In olden days this was achieved in a central control room where all these measurements were

displayed in the form of indicators, recorders etc. and some local panels in the field where some

specific monitoring was carried out.

But these indicators had the following limitations

1. Limitation of Physical Space An indicator showing one measurement consumed lot of space.

2. Limitation of Simultaneity in Monitoring An indicator showing a feed water/condensate measurement was far away from an indicator

showing turbine measurement & simultaneous monitoring was difficult. More number of

operators were required and co-ordination between over burdened and tensed operators

under emergency condition was difficult.

3. Limitation of Historical Storage The only device capable of historical storing for future reference was recorder which could

only store very limited no. of analog points and for a limited time. Most recordings of values

& events had to be done manually.

4. Lack of Flexibility It was very difficult to change assignments of plant input to various indicators/recorders.

© PMI, NTPC 156

5. Unavailability of Processed/Calculated Data Efficiency of the Plant and equipment performance calculations had to be done manually.

All the more these indicators suffered from lack of accuracy because of scaling factor,

limitations of range & parallax error.

Hence a need was felt for computerized intelligent system presenting data from the entire

plant in desired and on as required basis to facilitate easy monitoring, recording and to

enable operator to take quick decisions regarding operation. This could only be possible

with the help of a digital computer and this lead to the concept of computerized data

acquisition system (DAS) for power plant monitoring and smooth operation.

COMPUTER BASED DAS This system has the following features:

IN THE FORM OF DISPLAYS ON CRTS

(with a facility of display & hard copy print out) through simple key strokes/dedicated key.

1. Variety of plant data in the form of analog measurements displayed on CRTs (Display units)

in the form of group reviews (organized. in plant functional; groups).

2. Graphics Graphics showing the replica of entire plant & its subsystems & individual equipments

embedded with live plant data-current values of temperature, pressure and the status of

different pumps, motors etc. through alphanumeric or color codes (e.g. red for ON and

green for OFF) gives the feel of the entire plant in its latest status to the operator. This is

also helpful for new operators to learn plant operation quickly.

3. Bar Charts

© PMI, NTPC 157

Bars (both vertical & horizontal) showing like analog measurements e.g. reheater tube metal

temperatures help the operator to compare measurements to find the hottest spot etc.

4. Alarm Displays • These displays helps in annunciation of a lot of abnormal conditions not covered in the

annunciation window.

• These displays help in pin pointing the individual alarm, which led to a group alarm in the

annunciation window. Further exact measurement values & the rate of change there of

can be seen on CRTs.

5. Historical Storage X-t plot shows plot of a physical variable like main steam pressure, Generator Load with

time nearing different intervals like 10 sec, 1 mts, 10 mts, 1 hrs, 24 hrs even 1 day etc.

Group trends shows values of different inputs collected at different intervals over a period of

time.

6. Plant Start up Guidance Messages (PSGM) & Operator guidance Messages

(OGM) Plant start up guidance messages shows the different steps/criteria to be taken/fulfilled

before starting an equipment in the form of flow charts with the current status of the

step/criteria being completed/fulfilled or not. An operator guidance message shows the

various steps to be taken by the operator in the event of a fault etc.

These displays are particularly very useful in starting/shut down of the unit.

IN THE FORM OF PRINTOUTS (LOGS)

Three (3) types of logs are recorded in the system. Event & Time activated & Operator demanded

types.

a. Event Activated Logs Bata for these types of logs are collected & printed on event change(s)

© PMI, NTPC 158

1. Sequence of Events Reports This reports contains a list of plant events in the chronological order of occurrence

(with a capability of distinguishing two events with a time difference as low as one

millisecond) following a major event/break down such as unit trip/auxiliary trip. This

report helps in quickly pin-pointing tae reason for the unit trip/auxiliary trip by tracing

the sequence of events & in the restoring the unit/auxiliary.

2. Post Trip Log In the event of unit trip/auxiliary trip, value's of certain important parameters before

& after the trip are printed in this report which also helps the operator to analyze the

trip and finding the reason for the fault.

3. Start-up/Run up Logs

There are two such logs: Boiler start-up & Turbine Run up log.

4. Start-up Log The system includes the capability to generate Boiler and Turbine Start-up Logs.

Each start-up Log (Boiler and Turbine) consists of 100 essential to start-up points

subdivided into 10 groups, 10 points each. Upon Control Room Operator command,

the appropriate start-up Log stores on bulk memory (drum or disk) data at a pre-

assigned period of time apart for each point assigned to the specific Start-up Log.

The period for data acquisition is operator selectable (1, 2, 3, or 5 minute intervals for

turbine run-up log and at either 3,5 or 10-minute intervals for boiler Startup log.

Intervals are selectable by operator. Log is initiated by turbine roll-off for turbine run

up log and at the start of the boiler purges sequence for boiler start-up log and is

stopped by the operator. The system outputs the start-up log automatically upon

completion of collection of each 30 sets of data. There is also the capability to

generate on-demand printout of all stored in the memory but not printed out

previously sets of data.

© PMI, NTPC 159

TURBINE RECALL LOG

The turbine recall log is initiated by the occurrence of any one of several alarms and consists of all

data defined for the turbine diagnostics log. The system stores information whenever the turbine

generator is on-line.

The data is stored in the computer memory at the one minute intervals. A total of 30 minutes of

latest data is stored in the memory. Following the initial 30 minutes of operation, the oldest data in

the memory is discarded and replaced with new data. The log printout is initiated by preselected

alarm conditions and continues at 1 minute intervals after initiation of the log until the alarm

condition has disappeared or until stopped by the operator.

TURBINE SHUTDOWN ANALYSIS LOG

A log of up to 100 turbine data points is printed whenever the generator is taken off line. Data,

except turbine speed, is collected at 2 minute intervals. Turbine speed is collected at 1 second

intervals for the first 5 seconds after the shutdown is initiated and at 2 minute intervals thereafter,

the log continues until terminated by the operator.

Time Activated Logs

Data for these logs are collected & printed periodically at regular intervals.

Hourly Log

An hourly log of up to 150 points is provided to furnish data for routine analysis of plant

performance. This log is printed automatically and on demand in the form of shift log and daily log.

Shift Log

Shift log consists of 150 points subdivided into 15 groups of 10 points each. The values are stored

each hour on the hour, and are cumulative, average or instantaneous values; all values outputted to

© PMI, NTPC 160

the log which are unreliable, or where the value is calculated from unreliable points is indicated as

unreliable with an asterisk, or similar symbol.

The report is automatically output at the end of each shift and upon Control Room Operator

request, and is available for inspection of the incoming shift supervisor to acquaint him with

performance of the generating unit during previous shift.

The shift log, when generated automatically at the end of each shift, is output to the log printer and

to the magnetic tape units.

Daily Log

Daily Log is a plant management and accounting oriented log, and like hourly log & shift log

consists of 150 points subdivided into 15 groups of 10 points each. The values are automatically

stored each hour on the hour, and is cumulative, average or instantaneous values as selected. All

values outputted to the log, which are unreliable, or where the value is calculated from an unreliable

point shall be indicated as unreasonable with an asterisk or a similar symbol. The system permits

assignment of any analog input, calculated value, transformation, or digital input too the daily log.

The log output automatically, at midnight, to the log printer and to the magnetic tape unit. The

operator may request a review of the data collected for the daily log at any time.

This includes incomplete average, integration and totals. The printout includes a summary of all

hourly data saved since midnight and the last line is totals, average integrations of all data up to the

last hour to the time of the request. However, this Control Room Operator demanded printout is

output to the utility printer only and does not eliminate the requirement to produce Daily Log at

midnight.

Turbine and Generator Diagnostic Log The turbine diagnostic log shall contain up to 100 turbine and generator data points to be used in

analyzing possible turbine and generator trouble. The operator shall print out the data on demand.

Once the log printout is initiated, data shall be collected and printed out every minute until four sets

of data have been recorded.

© PMI, NTPC 161

Summary Log

The system shall permit the operator to specify up to 5 summary logs of up to 25 points each to be

printed out on demand. The summary logs shall consist of a report of the processed results of data

accumulated for the previous 24 hour period. The logs shall include but not be limited to; daily

maximum, daily minimums, hourly values, duration of a point in high and low alarm.

OPERATOR DEMANDED LOGS/SPECIAL LOGS

Performance Log Provision shall be made for logging up to 100 calculated points (Class II) performance calculation

results.) The log shall be printed automatically once a day or on demand at any time and shall

consist of hourly values of the calculated points using the most recent averaged data every hour.

Test log

The log consists of 50 parameters obtained to be monitored in a very short time span.

Vibration log

This log consists of all vibration inputs.

Motor start limit log

This provides a record & warning of 6.6 KV motor start limits.

Maintenance data log

This log records operating /maintenance information about certain plant equipment for the purpose

of scheduling preventive maintenance & routine equipment inspection.

© PMI, NTPC 162

A few sample logs displays taken from Singrauli Stage-II DAS/V.S.T.P.P. are given in figure 60 to

63.

SUMMARIES

These displays/printout enable the operator to review a specific class of points.

Alarm summary

Pint/display all points (analog, calculated, and digital) that are off normal at the bane the request are

made by the operator.

Off-scan summary

Print/display all points (analog and digital) that are off scan at the time the request is made by the

operator.

Constants summary

Print/display a list of all plug-in constants (those normally used as constants and those used as

substitutes for inputs points used in calculations).

Scan period summary

Print/display all scanned inputs by point ID number listing point English Description and assigned

scan period.

© PMI, NTPC 164

Point quality summary

Print/display all points with other than good quality tag by point ID number listing point English

Description and quality tag. Such information as cause of bad inputs, value/status of substituted

inputs shall also be included in the summary.

Trend Log Summary

This summary will list all group (a total of 16) that are ready for trending or being trended. The

display /printout shall include each group identification (group header) and shall list all points

assigned to each group.

Analog Recorder Summary

This summary will display /printout for each recorder, the point ID, Point English Description are

scale for all variable assigned for trending on the recorder.

Bar Graph Assignment Summary

Upon Operator /Programmer command the system shall display/ printout Bar Graph Assignment

Summary.

Recorder Pens Assignment Summary

Upon Operator/ Programmer command the system shall display printout listing of recorder pens

and their assignment.

Alarm Annunciator Group Summary

A number of selected analog and digital points may be assigned to an annunciator window and to

computer monitoring. There shall be 25 alarm annunciator groups, each associated with an alarm

annunciator window, (e.g., turbine pressure high, turbine temperature high etc.). Each alarm

annunciator group shall be capable of accommodating up to 32 points.

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Upon activation of the specific alarm annunciator window the Control Room Operator will request by

actuation of a dedicated pushbutton and a numeric code for the group number, the display/ printout

of the status of all points within the group.

Operator request summary Log-Displays/prints the operator requests in the last 24 hours.

PRINTER ASSIGNMENT FOR LOGS/SUMMARIES, ALARMS & EVENTS DATABASE CHANGE ETC.

Alarm Printer/Alarms

Utility Printer - Sequence of events report, Past Trip review log, & all on-demand logs/summaries.

Line Printer

Hourly log, shift log, Daily log, Performance log, Summary log.

Engineer's Printer - All data base change, log pt. changes. Test log etc.

Also, there are two types of performance calculations.

1. Class I - These calculations are related to the safe operation & protection of the equipment

e.g. reheater temp. approach to saturation temp.

2. Class II - These calculations are related to the efficiency of these equipment.

These packages are supplied on Engineer's Station

i. On line data based Editor This editor is used to modify parameters of an input such as alarm limits, pt. assignment to

logs/reviews/summaries etc.

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ii. Log builder Log builder - This is used to build new logs specifying the points, period of collection,

printing time, collection/printing etc. Also, formatting of logs is possible.

iii. Graphic builder This is used to build new graphic.

iv. Also, we can develop stew programmes in FORTRAN, compile, link & sum them in the real

time environment. (Simultaneously with the programs performing DAS functions running.

v. Also there are on line and off line diagnostic packages to help isolate any fault in the DAS.

Hardware

Generally, there are two CPUs, one main (master) & the other standby. Each CPU has its own

working memory (RAM - where programs ate run in real time mode) & bulk memory (which stores

all the system & application programs, graphics, log configuration data & files needed to transfer

programs to main memory). Also there is a data link between two CPUs for periodic data transfer

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to up date the slave CPU so that the slave CPU is having the, latest plant information if it takes over

from main CPU.

I/O Cards

These are I/O cards (both analog & digital) which scan the plant inputs by means of Analog/Digital

multiplexers at the specified rate which are housed in an I/O extension rack which are accessible to

both CPUs.

CRTS

There are 4 CRTs in control room:

1. Operator CRT Separately table mounted in control room,

2. Utility CRT Two on the panel.

These CRTs display graphics, detailed plant information & operator

requested displays.

3. Alarm CRT To display alarm messages in chronological order of occurrence.

2 CRTs in DAS room.

4. Engineers CRT Format generation/modification for graphics, logs, database etc.

5. System CRT For programmes, computer interface, Computer failure/Diagnostics

messages, Programme development.

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Printers

There are three printers in Control Room - Alarm, Utility & Line & two printers - Engineers &

System.

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In addition to the above, the system has two magnetic tape units for historical storage of plant data.

System Parameters

The system should meet the requirements of:

1. Duty cycle Which is a measure of the CPU load & is max. 75% (under worst case condition) & 50%

(under normal case conditions). This is to ensure that the DAS is equipped to process any

no. of plant changes & always latest information is available with quick response in any

case. This also allows the expansion capability in terms of plant I/O, new programmes etc.

2. Response time This is defined as the time between the pressings of any key on the keyboard to call a

display & the appearance of the display on the CRT. This time varies from 1-5 seconds

depending on the display.

3. Accuracy The overall system accuracy from analog input terminals to output presentation on CRT

displays, printers etc. & trend recorders is within ± 0.1%.

4. Reliability/Availability The reliability of the system is demonstrated by an analysis of system availability during

system design and by test upon installation in the plant. The guaranteed system availability

is as high as 99.7% over a period of six months.

As an examples Singrauli of 2x500 MW DAS supplied by Hitachi, Japan is described below:

This system is based on dual CPU-one master & other standby. (Pl. refers fig. 64). Each CPU (H-

80M) has 512 KW of working memory, 4MW of bulk memory (IC file) a floppy disk & console CRT.

Both CPU's can access 35 MW (2x17.5 MW) Fixed Disk through multiple access controller (MAC).

There are two buses a set of devices (Operator & utility CRTs, Alarm Printer, Analog Input & Digital

inputs, Trend recorders, & one Mag. tape) are connected to one bus and the other bus connects

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another set of devices (supervisor CRTs, supervisor Printer, programmer CRTs, Log Printer,

programmer Printers, Alarm CRT, other Mag. Tape).

The DAS has a communication processor (CLC-/µH) through which communication can be

achieved with other computer-systems.

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Hardware Features

CPU Model IDIC 80 M Word 6 bits instruction Set 51 Bus width Data 16 bits Address 32 bits control 6 bits Execution Time Addition 0.48 micro sec Multiplication 1.36 micro sec Floating point 1.84 micro sec Floating multiply 2.5 micro sec Main Memory Word 16 bites + 6 bits size 512 KW Cycle time 480 neno sec. Disk Model H-71 42C Storage 88 MW Data rate 188 KW/sec.

Access time seek 25 m sec. Rotational 8.5 m sec.

Mag Tape Model H-715/C Tracks 9 Density 1600 bpi Recording PE

Transfer rate 36 kw/sec. Speed 45 ips

IC File Storage 2 MB non volatile

Cycle 600 m.sec. Access width 16 bits Access time 100 micro sec. Transfer Rate 600 kb/sec. Error check ECC

CRT's Model 787 C-3 Screen 0" color High Resolution Formal 2 lines x 96 chars

5x7 dot char. size. Highspeed printers Speed 180 cps

Char. Set 96 Width 132 chars Code ASCII

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System Software

HIDIC 80 DAS is having process monitor system (PMS) operating system. This is on-line, Real-

Time System with multi programming and multi-tasking functions. The basic unit of task controlled

by PMS is called task. A programme may comprise of no. of tasks with 10 different priority levels,

processing of task is done asynchronously. All the tasks have to complete the system measures

like allocation of CPU, memory or input/output devices, whenever a task has to suspend its

processing (e.g. wait for completion of I/C), task scheduling takes place and the next ready task

with highest priority is taken up for processing.

Real time needs can be taken care by giving an external interrupt (could be timer interrupt) to the

current task and starting another task for real time processing. PMS provides memory protection

against use of a task’s memory by another task, however it also provides an inter-task

communication system for transfer of data. PMS allows 2 grounds of operation: foreground and

background. The DAS application program runs in foreground. Program development and testing

can be done in back-ground. PMS separates programmes into 2 types: Resident (always resident in

main memory) and non-resident (swapping to auxiliary memory). Memory allocation to a program is

done in terms of pages (1024 words). 64 pages comprise a logical space, which is assigned to a

task. There are total 16 logical spaces numbered 0 to 15 logical space no. 0 is provided for

exclusive use by the PMS. Pages of logical space is mapped to the physical memory. Programmes

in a logical space can share information with other logical space by having a shared memory area.

This is achieved by mapping corresponding pages in two logical spaces to same pages in the

physical memory.

DAS has assembler, FORTRAN compilers.

Utilities • Compilation & Editing

• Job submission, debugging

• CRT format modification

• I/O data base change

• Calculation Data base change

• Log data format generation.

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Application Software

Apart from core hardware and systems software DAS needs application software for end usage. A

list of functions for which application software is written follows:-

1. Input Scanning & Processing Analog, Digital, SOE Remote input.

2. Calculations

• Basic Calculations Periodic calculations

Transformation

• Performance Calculations Equipment & Unit performance

3. Alarm Monitoring • High, Low, High-Low, Low-Low, High-High

• Display/printing of alarm message.

4. CRT Display Functions • Alarm message display every 2 sec.

• Graphic diagram every 5 sec.

• Video trend every 10 sec.

• Bar chart every 5 sec.

• Plant group display every 2 sec.

• Group alarm display every 2 sec.

• Periodic display every 2 sec.

• Operation guidance message.

5. Operator Request Functions • Display/print/entire a point value.

• Get/display/print time & date.

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• Acknowledgement of alarm messages.

• Analog Trending

• Summary Display.

6. Operator Report & Logging • Alarm printing

• SOE log

• Pre & Post occurrence digital trend.

• Data Group Print.

• Performance deviation summary log.

• Periodic log.

• Shift/daily log.

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7. Distributed Digital Control and Monitoring and Information System

BACKGROUND OF DDCMIS

The control and monitoring system as discussed herein refers to the sub-systems of closed loop

controls and open loop control system of various auxiliaries of SG & TG, and the monitoring and

information sub-system for complete plant.

In all the NTPC projects before FSTPP-II all these sub-systems were being treated as separate/

independent, systems, utilizing their own dedicated conventional hardware, using conventional

display devices like indicators and recorders and conventional push buttons and hand/auto stations

for manual control. NTPC has until now employed conventional, hardwired systems for the

modulating controls (closed loop control) whereas the short-sequence control & protection system

(open loop control system) for various auxiliaries of SG/TG were realized with electromagnetic

relays. Regarding monitoring, information and various displays, both colour CRTS/printers as well

as conventional display devices i.e. indicators & recorders have been employed with conventional

display devices acting as a back-up.

As stated above, hardwired solid state Analog Control systems with split architecture have been

adopted by NTPC for its various super thermal power plants so far. Though the same are working

satisfactorily they have got certain limitations. For example, in, conventional Control System the

necessity of assigning functions & distributing information by hardware results in considerable

problems and cost specially during engineering and installation. In the hardwired system any

addition or modification in plant often results in difficult 'problem if the modifications work is to be

performed late in the installation phases or possibly during the operation.

In the last few years however, number of important development have taken place in the field of

electronics the most important being the introduction of microprocessor.

© PMI, NTPC 177

The microprocessor nave completely revolutionized the basic Configuration, both in tears of

hardware as well as in terms of Configuration, operation etc. in the field of control and

Instrumentation. These microprocessor-based systems do offer number, of advantages over the

conventional system, like self-diagnostic and monitoring facilities, centralized operation &

monitoring facilities, flexibility etc. Hence, it is considered that these microprocessor based systems

are technically much superior to the conventional hardwired system and are also considered to be

more reliable due to their self-diagnostic features. Moreover, their availability and price now a days

has made it possible to employ separate micro-processors for different functions thus avoiding the

catastrophic failure i.e. complete collapse of the system due to the failure of one of these

microprocessors, which can happen in the case of centralized computer control system. Modern

power plants are employing the microprocessor based distributed digital control system for

modulating control and logic function due to the various advantages built in such systems. Number

of manufacturers in the different parts of the world have come up with DDC Systems and these

systems have been in service for many years thus establishing satisfactory performance records.

Moreover, because more and more power authorities are going in for DDC, the sales of

conventional systems are decreasing and hence the long term support by the manufacturers for

conventional systems is doubted. Hence, the DDC systems are now being adopted for NTPC's

projects from FSTPP-II onwards.

But before we embark on the study of distributed digital control monitoring and information systems,

let us first understand what do we understand by the term DDCMIS.

Distributed control implies that the actual control and management functions are in fact distributed

throughout the entire plant in several processing units.

In such configuration, plant is divided in many small groups and each group is controlled by a

dedicated set of processors and other hardware. The task of measurement, control, operation

communications, and sequence controls, etc. are distributed amongst a number of processing units,

each incorporating a microcomputer.

These microcomputers are linked via a common communication highway and are configured in a

hierarchical command structure: Distributed control thus represents the physical distribution of

digital controllers among plant processor and functional distribution of risk associated with

© PMI, NTPC 178

component failure. This arrangement provides the capability for implementing high level of

automations. The major features and advantages of this distributed hierarchical approach are :

i. If the computational tasks are shared between, the processors, the system capability is

greatly enhanced.

ii. The system is more flexible.

iii. If any microprocessor should fail, implications are not catastrophic, as only a portion of

system will not be available.

iv. It is easier to make software change is distributed systems.

v. The units in the system can become standardized.

vi. The interlinking of distributed units by a data highway means, they can be distributed over a

wide area.

vii. The availability of colour CRT based operator control centres provide more information and

guidance to operator for his actions.

viii. Control rooms are simplified as all information is available on CRTs.

IMPACT OF DDCMIS ON UNIT OPERATION PHILOSOPHY

Due to the fact that the control system is operating on digital devices, it becomes very easy and

convenient to provide digital devices such as CRTs, Keyboards, printers etc. as the operator

interface. These devices can be provided in addition to the other conventional devices such as

indicator/recorders etc.

Earlier in the power stations, implemented with DDC System, due to operator familiarity with

conventional devices, the main operation tools were still kept as A/M station and push button,

indicator and recorders etc. and CRT/KBDs were used on as an alternate path of operation.

© PMI, NTPC 179

But due to increasing familiarity with these system of operation and also due to increasing reliability

of these system operators are also depending more and more on CRTs/KBD operation, than on the

conventional devices. In NTPC also earlier, we had in the power station with DDC 100%

conventional back-up but in the recent units, we have drastically reduced the conventional

hardwired back up and the CRT/KBD has been kept as main man machine interface.

Accordingly, the unit operation philosophy of NTPC units has been envisaged as described below.

Operation Philosophy

The unit operation philosophy envisaged calls for control and monitoring of steam generator,

turbines generator and their auxiliaries and ancillary units in all regions of operation i.e. start up,

normal & shut-down operation through colour CRT/Key boards mounted on the unit control desk

(UCD) in the unit control room. In addition, all required conventional hardwired push button stations,

hand auto-stations, status indication lamps, indicators, recorders are also be provided as aback up

on Unit Control Board (desk-cum-panel) for important drives and parameters to achieve unit control

and monitoring in the event of failure/non-availability of CRTs/KBDs redundant svstem bus

controllers etc.

Since it is proposed to go in during normal mode of operation for centralized keyboard operation

through CRT/KBD with microprocessor based hardware. The system shall be provided with

redundant data bus for communication from CRT/KBD to control system. However, in case of

failure of data bus or CRT, the control system shall remain unaffected and same shall be operated

through hardwired backup conventional push buttons. The operator shall be provided with the

indication of some permissive conditions for the major auxiliary such as ID,FD fans etc., through

suitable means on the unit control desk. Only critical drives of closed & open loop both dedicated

drive control push buttons shall, be provided with operation enable push button on avoid

unauthorized operation of drive/sequence.

DISTRIBUTED DIGITAL CONTROL & MONITORING AND INFORMATION SYSTEM

The DDCMIS provides all functions required for the automation of power plant process like:

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a. Acquisition & Processing of process data. b. Open loop and closed loop control. c.

Calculation and optimization of the plant performance.

b. Open loop and closed control.

c. Calculation and optimization of the plant performance.

d. Monitoring, signaling, operation and visualization of the process in interactive mode on a

monitor or via conventional push buttons/indicators.

These functions of DDCMIS can be achieved in two ways i.e.

a. by geographically distributing the hardware.

b. by functionally distributing the hardware.

Geographical Distribution

In this concept the hardware is distributed geographically in the plant, i.e. the electronic modules

are not placed in a central location but segregated in small groups and kept near the respective

systems being controlled. (These systems have the advantage of saving a lot of cabling costs as

the signals need not be routed all the way to the central control Equipment Room). However, this

system concept is not used in NTPC because of the environmental conditions present, in Indian

Power Plants due to which it is difficult to maintain required environment for µP based hardware at

many places in the plant.

Functional Distribution

In this concept, the hardware is kept in a centralized control equipment room but the electronic

hardware is functionally divided to perform the functions independently, i.e. failure of one functional

group/sub-group does not affect or jeopardize another group/sub-group. This is the concept

adopted by NTPC as this needs only one centrally air conditioned room for the electronic modules.

© PMI, NTPC 181

SUB-SYSTEMS OF DDCMIS

The different functional blocks of DDCMIS are as follows

a. Measurement System (MS) for CLCS, OCCS and IS.

b. Control System (CLCS & OLCS).

c. Information system

d. System Bus

e. Man-machine Interface

f. Sequence of events recording system.

g. Master & slave clock system.

The three systems vie Closed Loop Control System (CLCS), Open Loop Control System (OLCS)

and Information System (ISO are connected to the System Bus. However, all the three systems are

independent of each other in all respects like functional independence, hardware independence,

and cabinet location independence.

MEASUREMENT SYSTEM

The measurement system shall perform the functions of signal acquisition conditioning and signal

distribution. Three measurement systems have been envisaged, one for Closed Loop Control

System (CLCS), one for Open Loop Control System (OLCS) and one for Information System (IS)

through signal Acquisition System (SAS).

The measurement system, accepts the following inputs:

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a. Analog Inputs

i. 4 -20 mA, DC input

Maximum input resistance to be 50 ohm 24 V DC loop power for 4-20 mA 2 wire/4wire

transmitters shall also be on part of the system.

ii. RTD Input

The system shall be capable of recurring 100 ohms 3 wire or 4 wine platinum RTDs and 53

ohm 3 wire or copper RTD's.

iii. Thermocouple Inputs

The system accepts thermocouples of the type E, J, K, R and T either directly wired to it or

through CJC Boxes mounted locally.

b. Binary Inputs

The system accepts binary inputs in the form of Normally Open/Normally Closed/Change Over

Contacts. The contact interrogation voltage in 48V which will also be supplied by the system.

c. Pulse Inputs

The system accepts servo based pulse or rectangular wave or sinisoidal wave form or potential free

or potential free contacts.

REUNDANT TRANSMITTERS FOR CONTROL SYSTEM

Multiple transmitters with monitoring circuit are used to ensure that the failure of a single transmitter

does not lead to malfunction or reduced availability of the related control system:

a. Dual Measurement System

Two independent transmitters preferably connected to separate tapping are employed. The outputs

of these transmitters are continuously monitored for excessive deviation. Such a deviation is logged

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by DDCMIS and alarmed on Unit Control Panel. Automatic change over provision is made available

from unhealthy transmitter to healthy transmitter during normal operation of control loops without

affecting the status of control loops. If other transmitter is not in working order, the control loop is

transferred from auto to manual mode. Facility is provided for selecting the output of any transmitter

for control purpose from the control desk. Facility is provided for defeating monitoring circuit.

b. Triple Measurement System

Triple measurement system is provided for critical measurements like furnace draft, feed water flow,

throttle pressure, turbine first stage pressure etc.

Three independent transmitters connected to separate tapping points are employed. The system

auctioneers the three signals to determine the median value signal which is used for control

purpose. The control loop trips to manual when any two of the three transmitter signals fail.

Appropriate messages/indication .is displayed/logged at DDCMIS. The conditioning, high deviation

between any transmitter, any value and the median value and any transmitter failure is

displayed/logged at DDCMIS. Adequate signaling indications are provided to immediately know

which of the three transmitters are working. Facility is provided to select any of the transmitter or the

median value for control from control desk. Facility is provided to defeat the deviation monitoring

circuit.

TYPES OF CONTROLLERS

Generally there are two hypes of controllers available.

• Single Loop Controller

• Multi Loop Controller

Single Loop Controller

In case of Single Loop controller dedicated controller hardware is envisaged for each loop of CLCS

& OLCS. Here all the Signal conditioning and processing functions are implemented in separate

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hardware independent of controller availability. Further in this alternative drive control module are

used for all power operated drives covered and OLCS (one for each drive) to get advantages of

built in monitoring, detailed status information, easy trouble shooting etc. and enable the use of

miniaturised control room tiles independent of controller availability with equipment protection

available for remote manual operation.

Multi Loop Controller

In case of Multi Loop Controller more than one loop of CLCS or OLCS can be implemented in a

controller. Here all signal processing are performed in the controller and remote manual operation

through miniaturised control room tiles is routed through the controller. However in certain systems

a drive level card is used as in the case of single loop controller to get the advantages of built in

monitoring detailed status information easy trouble shooting etc. This will also enable the use of

miniaturised control room tiles independent of the controller availability with equipment protection

available for remote manual operation. As many loops are clubbed into one controller, a controller

failure may lead to the failure or non-operability of many loops and these controllers are

implemented in redundant configuration.

CLOSED LOOP CONTROL SYSTEM (CLCS)

CLCS continuously acts on valves dampers or other mechanical devices such as Variators,

hydraulic coupling, etc. which alter the plant operating conditions. CLCS is designed to give a stable

control action in steady state condition and for load changes in the step/ramp over the load range

with Permissible variation in parameters, mainly governed by the characteristics of mechanical

equipments - Boiler and turbine.

Some basic requirements/features of CLCS are

1. The system is designed to provide higher level of control with maximum practicable degree

of protection in conjunction with various protection and interlocking conditions and provide

auto/manual operation under all operating conditions.

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2. To ensure that when permissible limits are exceeded automatic switch over from an

operation governed by maximum efficiency to an operation governed by safety and

availability is effected.

3. Any switchover from auto to manual, manual to Auto and switchover from CRT operation to

auto manual stations and vice versa are balance less and bump less. This will not result in

any change in the plant regulation.

4. The control system will be designed in such a way that final control element remains stay

put or fail safe position under the conditions of power supply failure, control signal failure.

5. Controller Capability

The controllers used in CLCS have following basic control functions:

i. P, PI, PD and PID control and their variations.

ii. On-off control

iii. Cas-cade control

iv. Feed forward control

v. State variable control (e.g. Super Heat/Re-heat temperature control).

vi. Ratio & bais control

vii. Logic Operation.

CLCS can be realised in any one of the alternatives, as described above (single loop integrity or

Multi-loop control), based on the capability of microprocessor based modules of a system.

Following closed loop controls are provided in a power plant:

1. Co-ordinated master control (CMC).

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2. Fuel flow control.

3. Air flow control

4. Furnace draft control

5. Feed water control

6. Primary air pressure control

7. Mill coal-air flow & temperature control

8. Super heat & Re-heat steam temp. control.

9. Deaerator level and pressure control

10. Condenser hotwell level control.

11. Condensate minimum recirculations control.

12. Air heater temperature control.

13. Other controls, specific to particular power plant.

CONTROL SYSTEM HIRARCHY FOR OPEN LOOP CONTROL

The four basic levels of open loop control system are:

a. Unit level control (highest level)

b. Group level control

c. Sub-group level control

d. Drive level control.(lowest level)

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The unit level control will not be possible to be adopted in NTPC because the sequence control for

main equipments like automatic turbine run-up system etc., are being procured through the TG

supplier, which may or may not employ microprocessor based system. Also the complete automatic

operation of the whole plant with single push button is considered to be premature step at this

stage.

In the group/sub-group/drive level control, is implemented open loop control system for

starting/stopping operation of major auxiliaries like ID fans, FD fans, PA fans, Air heaters, BFPs,

CEPS and their associated auxiliaries & valves/dampers through a single push button action.

Attempt is made to group the balance equipment drives on functional bases such as inlet, outlet

valves and their integral bypass valves of the heater and operate them sequentially by single push

button action. The individual start/stop-open/close push buttons criteria for that drive remain

effective both during the automatic operation as well as manual operation through hardwired push

button station. The protection signals (trip signals) for the safety of that drive remain effective under

all conditions and under all modes of operation.

In case of multifunctional controller configuration the basic protection system are implemented in

such a manner that even during both the controller's failure all the basic protection is available

during remote manual operation from the hardwired push button station.

In the case of multifunctional controller, it has been, observed that all the leading C&I

manufacturers supplying the system based on this type of controller configuration, generally

perform all the function of group/sub-group and drive level controller in one processor and provide a

hot backup for the processor i.e., all the open loop control function of the auxiliaries under one

group is implemented in one single processor and another processor is provided as hot back up

which automatically assures control in the case of failure of the primary processor. The basic

advantage in this kind of system is at no instance of time control is lost as the simultaneous failure

of both the processor is very much remote possibility. The output of this controller, through the

suitable output cards/modules are connected to the electrical switchgear motor control center. The

signals for the status indicating lamps are also connected through the output cards of the controller.

Hence as an alternative, the above configurations shall also be considered for the implementation

of open loop control system.

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SEQUENCE CONTROL

A sequence is used to move a group, sub-group from an initial steady state (for instance OFF) to a

final steady state (for instances ON). The sequence initiating command for the group level is issued

from CRT/KBD. The sequence initiating command for the sub-group level is also issued from either

CRT/KBD.

A sequence is made of steps. The steps get executed in predetermined order according to logic

criteria. For each step there is a provision for waiting time and monitoring time and it outputs an

action on the process.

Desired number of criteria acts as pre-conditions before the sequence control can take off to

execute its designed programme. The programme comprises of different number of steps and for

each steps there are designed number of criteria required to be fulfilled.

Under normal conditions of the equipment each step is completed within the specified time

otherwise a message gets displayed on control CRT indicating that specified monitoring time is

getting exceeded and programme is not proceeding further.

Protection command always have priority over manual commands, and manual commands always

prevail over auto commands. Open or Close priority is selectable for each drive. The possibility of

bypassing and/or simulating one or more criteria to enable the programme to proceed is provided.

The sequence start is of the following types.

a. Automatic Mode

In this mode of operation, once the sequence memory is latched the sequence shall

progress without involving any action from the operator.

b. Semi-Automatic Mode In this mode of operation, once the sequence is initiated the step execution command shall

be interlocked and shall be sent by the operator via the keyboards.

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c. Operator Test Mode In this mode of operation the complete system will run and receive inputs from the plant and

the push button station /Keyboard, but its command output is locked. This mode shall allow

the. operator to practice manual operation using step & criteria indication.

BASIC PROTECTION SYSTEM

The protection system based on single channel only has been envisaged, except for very critical trip

inputs, viz. deaerator level very low etc., where redundant triple sensing devices shall be envisage.

The protection system input channels shall be based on two out of two, two out of three selection.

The logic circulatory shall be based on one out of one DC energies to trip only.

System Bus

As indicated above, redundant system bus is employed.

The system bus is effectively immune to the types of electrostatic and electromagnetic interference

that can be expected in power plants. Both redundant system bus will operate at all times. There

will be no need to "Fail Over" and initialize to a stand by highway. Failure of a system bus or one of

the drops on the bus will be alarmed. Mastership of the system bus will not reside in a single

device. No single failure will prevent the orderly and timely transmission of data. It will be possible

for any drop on the system, bus to fail or to be physically removed/replaced without interrupting full

communication of all other stations. Communication systems have message check facility. (Any

command given from CRT/Keyboard complete its action within one second.)

Man-Machine Interface

Separate man-machine interface station are provided for the control system and monitoring &

information system (IS). The operating station for the control system consist of control

CRT/Keyboards, colour graphic printer and dot matrix printers.

The control CRTs (colour) will provide complete monitoring, supervisory and display functions for

control system (CLCS + OLCS) variables and control system status and all other inputs connected

© PMI, NTPC 190

to control system hardware. The operator will normally control the plant through these displays. It

will be possible to perform both closed loop and open loop controls from these individual

loop/sequence displays etc. The displays will include all control related displays, bar graph displays,

group displays, control system alarms and real time trend displays. The operating station shall

monitor its own operation and the operation of system bus on an on-line basis and will provide

alarm in the event of any failure. The failure of operating station or/and the system bus shall not

affect in any way the functioning of closed loop and open loop control systems. All control CRTs of

the Operating Station will be fully assignable and interchangeable under all operating condition and

failure of any CRT, system bus or part of system bus will not result in loss of any display or control.

Information System (IS)

The IS is an on-line system which processor display and store information to provide the operator

either automatically or on demand the required and relevant information. It receives data, from

closed loop control system and open loop control system through the system Bus. All other inputs,

which are not connected to the open loop control system and closed loop control system and

required only for monitoring, are connected to the information system.

It performs the following functions as a minimum.

1. Operator Interface

2. Calculations

3. Alarm Monitoring and Reporting

4. Displays

5. Logs

6. Trend Recording

7. Historical Storage

© PMI, NTPC 191

All The information available in the control system is also fed to the Information and Monitoring

System.

IS have its own operating station with two colour utility CRTs, one alarm CRT, one colour graphic

printer and two Dot Matrix Printers & one line printer connected to it. Further, the Information and

Monitoring system will also be fed with the information from C&I systems supplied by the SG & TG

SUPPLIERS, like BMS, ATRS etc., through proper interface and couplers to get the required

displays, print outs, startup logs, start-up and shut down guidance etc. The information from stand

alone sequence of events monitoring equipment will also be fed to the Information and Monitoring

System for historical storage purposes.

PROGRAMMING FACILITY

For programme development/modifications, modifications in logs, database, etc. and for

structuring/configuring and tuning CLCS & OLCS Controllers, programmes stations are provided.

Three programme stations are provided

1. Structuring/Configuring and Tuning Unit for CLCS/OLCS Controllers Control system is configurable and changes in it are done with the help of software

implemented functional blocks by this programmer station. All such modifications can be

done online without causing any disturbance in the execution of the control loops.

2. CSPIS Programmes Facility

By this programming station, CSPIS data base modification/Creation; testing of software of CSPIS

and generation & editing of CSPIS graphics and logs is achieved. Facilities are provided for down

loading the CSPIS software with associated database from this programming console to the various

distributed processing and control units from already stored data on-line.

3. IS Programming Facility

A console is provided to achieve the following basic functions:

© PMI, NTPC 192

1. Development /modifications and testing of software of IS.

2. Generation & modification of graphic and logs and data base of IS.

3. Facilities to reload the system module from already stored data on-line.

SEQUENCE OF EVENTS RECORDING SYSTEM (SERS)

An independent microprocessor based stand alone system with a time resolution of 1 millisecond

shall be provided. The SOE inputs shall be in the form of potential free contacts from the field. 48 V

DC contact interrogation power supply shall be provided for these inputs. The quantity of sequence

of events inputs for each generating unit shall be 650. The SERS shall be hooked up with

monitoring & information system to transfer data for historic storage/retrieval and for printing on the

line printer as a backup. System terminal (Printer + Keyboard) shall be provided from where it shall

be possible to modify data base, change point IDS; adjust filter delay timer, take a point offscan, get

SOE report printout etc. The reports generated by the SERB shall include:

• SOE Alarm Report

• Pre-fault Report

• Post fault Report

i. SOE Alarm Report

All SOE points entering from normal state into the alarm or returning from alarm state to the

normal state shall be reported.

ii Pre-fault Report

The fault shall be pre-defined trigger event. When the event occurs, the pre-fault memory

containing the state of all inputs designated as pre-fault points shall be printed out.

iii. Post-fault Report

When a pre-defined post-fault trigger event occurs, all inputs designated as post fault points

shall be printed out as they change status, until the trigger event changes state or operator

manually stops the print out.

© PMI, NTPC 193

MASTER & SLAVE CLOCK SYSTEM

A master and slave clock system is envisaged to provide uniform timing throughout the various

plant facilities. It shall include a master clock & slave display units. The master clock shall employ

highly stable crystal oscillator to ensure accurate time indication. The stability shall be better than

0.5 sec./day. The master clock shall be synchronised with DDCMIS (both CSPIS & IS) once every

twenty-four hours.

A typical DDCMIS configuration proposed for Talcher STPP Stage-I (2 x 500 IOW units) is enclosed

(See Fig. 65).

control & instrumentation 2

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