200MW Trainig Simulator Volume 2

KORBA SIMULATOR

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KORBA SIMULATOR

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KORBA SIMULATOR

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CONTENTS CHAPTER NO.

TOPIC

1.

CHARGING OF ELECTRICAL SYSTEM

2.

CONDENSATE AND FEED WATER SYSTEM

3.

7-11

CEP OPERATION

15-20

BFP OPERATION

21-28

BOILER SYSTEM

AUXILIARY PRDS CHARGING

31-32

HEAVY FUEL OIL SYSTEM CHARGING

33-34

FSSS LOGICS

35-74

AIR PRE-HEATER OPERATION

75-78

ID FAN OPERATION

79-84

FD FAN OPERATION

85-88

FURNACE PURGE

89-91

BOILER LIGHT UP

92-96

PA FAN OPERATION PULVERISER OPERATION 4.

PAGE NO

97-102 103-108

TURBINE AND GENERATOR SYSTEM

VACUUM PULLING

HP/LP BYPASS CHARGING

KORBA SIMULATOR

111-114 115-116

TURBINE START-UP

117-120

TURBINE ROLLING

121-124

4

GENERATOR SYNCHRONISATION

125-128

UNIT SUPPLY CHANGEOVER

129-130

LP HEATERS CHARGING

131-132

HP HEATERS CHARGING

133-134

SH/RH STEAM TEMPERATURE CONTROL

135-136

SOOT BLOWING OPERATION

137-139

5.

UNIT COLD START-UP

141-156

6.

UNIT HOT START-UP

157-162

7.

8.

AUTOMATIC TURBINE RUN-UP SYSTEM (ATRS)

163-208

SGC OIL SYSTEM

171-182

SGC TURBINE SYSTEM

183-208

UNIT PLANNED SHUTDOWN BOILER SHUTDOWN

211-212

TURBINE SHUTDOWN GENERATOR SHUTDOWN

213-215 216

9.

EMERGENCY HANDLING

217-255

10.

EFFICIENCY ASPECTS OF POWER PLANTS

257-288

11.

SIMULATED MALFUNCTION LIST

289-296

12.

APPENDIX BOILER STARTUP CURVES

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TURBINE STARTUP CURVES

299-306 307-317

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UNIT POWER SUPPLY: SINGLE LINE DIAGRAM

1.

ACTION

ENSURE all the following conditions are satisfied, before charging the unit HT/LT buses.

KORBA SIMULATOR

REMARKS OBSERVATION

-

ADEQUATE service air pressure is available for 400 KV breakers (30 Kg/cm2 )

-

Local check/ operation. Not simulated.

-

Bus section coupler on 400 KV lines is CLOSED

-

Switchyard check.

-

Bus-coupler on 33 KV Bus in OPEN.

-

Switchyard check & operation

8

-

Tie Xmers 1 & 2 are CHARGED from 400 KV and 33 KV sides.

-

Switchyard operation. Not simulated.

-

33 KV bus voltage is NORMAL.

-

Switchyard check.

-

Switchyard check.

-

-

All the protections are HEALTHY and in SERVICE.

-

EMD Engineer's clearance, required.

-

Bus couplers connecting buses SA & SC and SB& SD are OPEN.

-

Not simulated.

Station transformer's incoming breakers from 33 KV buses outgoing to 6.6 KV buses (SA, SB, SC & DC) are CLOSED.

-

Not simulated.

"Power available" indications are ON, to all the four station buses (SA, SB, SC & SD).

-

Common Station Supply Auxiliary Electrical Panel. C.S.S.A.E.P.

-

2.

CLOSE both the HT (6.6 KV) incomer breakers to unit auxiliary buses 1-A and 1-B from station buses SA & SB.

3.

CLOSE the H.T. side breakers and then L.T. side breakers of the unit service transformers (UST).

KORBA SIMULATOR

220 V DC supply is AVAILABLE.

Buses I A and I B get charged and their voltages come to 6.6 KV , " 6.6 KV bus volts/ VT trouble", alarm gets reset.

UCB Operation/check.

-

Bus sections LA and LB get charged and their voltages come to 415 V (approx.)

-

UCB indications.

-

USTs in rush current momentarily shoots up meter pegs out and drops to no load value.

-

UCB indication.

-

All the "power/control

-

UCB annunciation. 9

supply fault" and "UATs cooler/ OLTC trouble and "415 V boiler/turbine MCC fault" annunciations reset. 4.

5.

CLOSE the normal tiebreaker to AC emergency section.

CLOSE the incomer breakers to ESP & lighting Xmers.

KORBA SIMULATOR

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AC emergency section tie breaker gets charged and voltage shows 415 V (approx.)

-

UCB operation

-

All annunciations pertaining to Emergency MCC get reset.

-

UCB indications

-

"ESP switch gear trouble" alarm gets reset.

-

UCB indication .

10

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CONDENSATE AND FEED WATER SYSTEM

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CEP OPERATION PRE-START CHECKS OF CEP

CONDENSATE SYSTEM

1.

ACTION

CHECK if all start permissive for starting CEP is satisfied.

OBSERVATION -

-

-

-

KORBA SIMULATOR

CEP suction valves MC-1/MC-2 are OPEN.

Hot well level is ADEQUATE (300 mm wcl.)

-

-

Bearing temperature of CEPs is NOT HIGH 60 0 C.) CEP re-circulation valve MC-33 is OPEN 100%.

-

REMARKS

Local operation.

UCB indication. Also to be locally checked.

UCB indications and also to be locally checked Hotwell level controller output is zero.

14

2.

3.

CHECK that CEPs are locally lined up for starting.

ENSURE condensate system is lined up before starting CEP.

-

CEP discharge valves are CLOSED (MC-5/ MC-6).

-

UCB operation. Interlock, before starting the first CEP.

-

Condensate pump gland sealing waterisolating valve is OPEN.

-

Local operation. Not simulated.

-

Condensate pump priming (pressure equalising) valve is OPEN.

-

Local operation Not simulated.

-

CEP bearing cooling water line isolating valve is OPEN.

-


-

CEP bearing oil level is adequate.

-

Local check.

-

Local emergency push button is released.

-

Local operation check.

-

CEP electrical supply is AVAILABLE.

-

Breaker is in Service/Remote position.

-

Main ejectors inlet/outlet- valves are OPEN (MC-11/MC-12 and MC-13/MC-14). Bypass valve (MC-15) is closed.

-


-

Gland steam cooler inlet/outlet valves MC19/MC-20 are open and bypass valve (MC21 is CLOSED.

-


-

LPHs (1-2-3) inlet/ outlet valves (MC61/MC-63, MC-67/ MC-68, MC-72/MC-73) are CLOSED.

-

Local operation (Remote function).

-

Local operation. LPHs are bypassed initially to minimise corrosion.

-

KORBA SIMULATOR

LPHs (1-2-3) bypass valves (MC-64/MC69/MC-74) are OPEN.

15

-

Deaerator inlet valve (MC-75) is OPEN.

-

Local check Not simulated.

-

CEP header vents and line vents OPEN.

-


-

HW level controller, DA level controller and cycle make-up controller valves are CLOSED. (MC-27, MC-41 and MC-55)

UCB operation and check.

-

Bypass valves of HW, DA and cycle make-up controllers (MC28/MC-42/MC-55 respectively) are also CLOSED.

-

UCB operation and check.

-

Local operator intimated prior to starting of pump.

-

Use plant PA system to inform the operator.

GLAND STEAM COOLER AND EJECTOR CONNECTIONS

KORBA SIMULATOR

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STARTING PROCEDURE OF CEP WHEN BOTH THE PUMPS ARE OFF

1.

2.

ACTION

CHECK before starting any condensate pump.

START the CEP motor.

-

REMARKS OBSERVATION

All pre-start checks are OVER.

-

Local /UCB checks & operation

-

All permissive are AVAILABLE.

-

Associated saffron lamps on.

-

CEP starting current comes down to 20A after 5 sec.

-

UCB ammeter indication.

-

CEP discharge pressure increases to 25 Kg/cm2. Approx.

-

UCB indication.

-

CEP's discharge valves (MC-5 MC-6) open 100%.

-

Associated red lamps come on.

3.

CLOSE the air vents on condensate lines.

-

The air vents are locally closed.

-

Local operation Not simulated

4.

LOAD the condensate pump by opening MC27.

-

CEP current starts increasing

-

UCB ammeter.

-

CEP discharge pressure decreases proportionately.

-

UCB check.

-

Condensate flow to D/A starts increasing

-

UCB indication.

-

UCB OMNIGUARD brg temp and vibration indicators must be regularly checked.

5.

INSTRUCT the local operator to check bearing temperatures and vibrations.

-

Limiting values of bearing temp and vibrations are:

Bearing Temperature

Vibration

KORBA SIMULATOR

Alarm 75 oC

Trip 90 oC

40 microns

75 microns

17

6. CHECK that the second condensate pump is ready for starting and is available on STANDBY.

-

Breaker control switch is on 'Normal After Stop' position.

-

UCB control switch on 'off' position

-

-

All permissive are SATISFIED.

-

UCB check.

-

All local line ups are COMPLETE

-

Refer to pre-start checks list.

Pump OK standby

WHEN ONE PUMP IS RUNNING ACTION

1.

2.

-

OBSERVATION

CHECK beforestarting the second condensate pump that all these conditions are satisfied.

START the CEP motor

CHECK bearing temperatures and vibrations locally.


KORBA SIMULATOR

UCB/local check.

All associated saffron LAMPS ARE ON.

All permissive are AVAILABLE

-

-

CEP motor breaker gets closed.

-

CEP discharge header pressure improves a little.

- At a discharge pressure of 17.5 Kg/cm2., the standby

-

The motor current of the other CEP drops slightly.

-

Bearing temperatures and vibration limits are

Bearing Temperature Vibration

-

-

REMARKS

CEP can take start automatically.

-

UCB OMNIGUARD and vibration indicators must be monitored regularly.

Alarm 75 oC

Trip 90 oC

40 microns

80 microns

18

CEP SHUTDOWN PROCEDURE WHEN ONE PUMP IS RUNNING

1.

2.

3.

ACTION

OBSERVATION

Start the other CEP if it is available.

STOP the first condensate pump. CLOSE the suction and discharge valves. If any maintenance is to be carried out, rack-out the motor breaker.

Discharge pressure improves slightly

REMARKS

-

Maintain hotwell level approx 500 mm wcl.

-

MC-27 closes slightly on auto.

-

Discharge pressure falls slightly.

-

Hotwell level HI alarm is at 600 mm wcl.

-

Suction and discharge valve closed indication comes on.

-

Hotwell level LO Alarm 400 mm.

-

Hotwell level LO-LO Trip is at 250 mm wcl.

WHEN BOTH PUMPS ARE RUNNING

1.

ACTION

TRANSFER MC-27 control to MANUAL and CLOSE it to 20% approx.

STOP the CEP motor.

KORBA SIMULATOR

OBSERVATION -

Manual mode on indication comes on.

-

Discharge header pressure goes up slightly.

-

The discharge header pressure may tend to drop further.

REMARKS

- M/A release push button must be pressed for all auto/ Manual change over.

- If required, close MC-27 more to maintain discharge header pressure.

19

BFP OPERATION PRE-START CHECKS OF BFP

1.

ACTION

CHECK all the BFP start permissive is satisfied before starting any BFP.

KORBA SIMULATOR

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OBSERVATION Deaerator level is ADEQUATE (700 mm wcl)

REMARKS

-

UCB indication, also check locally.

-

BFP suction valve (FW1/FW-2/FW-3) is OPEN 100%.

-

Local operation. UCB permissive indication. Not simulated

-

BFP booster pump suction pressure is ADEQUATE (>3.0 KSC)

-

Local check. UCB indication for permissive.

-

BFP pneumatic recirculation valve (FW8/FW-9/FW-10) is 100% OPEN.

-

Re-circulation controller output is 100% and valve open indication available.

-

BFP manual re-circulation valves at the Deaerator are 100% OPEN.

-

Local check only. Not simulated.

-

BFP cooling water pressure 2 is ADEQUATE 2.5 Kg/cm

Local operation and check.

-

BFP bearing temperatures are less than 60 OC.

-

UCB and local CHECK Saffron lamp on indication is available.

-

BFP lub oil pressure is 2 ADEQUATE (2.0 Kg/cm ).

-

AOP for the BFP is on and on "Remote". If not, start the AOP from UCB.

-

BFP selector switch is on NORMAL.

-

For UCB operation (interlock).

-

BFP scoop tube is on MINIMUM position.

-

Operator check only

20

2.

3.

CHECK that before BFP is locally LINED UP starting.

BFP lub oil, working oil and seal water coolers are in CHARGED position. All manual valves for cooling water to bearings are OPEN.

-

Local operations. Not simulated.

-

BFP motor air box cooling water-inlet/ outlet manual valves are OPEN.

-

Local operation and check. Not simulated.

-

BFP suction strainer DP is 0.2 Kg/cm2

-

Local check.

-

All air vents on suction and discharge lines of BFP and feed regulating station are OPEN.

-

Local check. Not simulated.

CHECK that feed water system is lined-up (Required only for the first BFP to be started).

-

Spray pressure control valves on HP bypass & AUX. PRDS station are CLOSED.

-

UCB check only.

-

Suction strainer drain valve is in CLOSED position. HPHs are in BYPASSED condition.

-

Local check.

-

Feed regulating station control valve are in CLOSED position.

-

Group bypass valves are in 'Bypass' mode or individual HPHs Bypass valves are open. UCB check.

-

Economiser inlet valve E-2 is open.

-

UCB check only

-

Header block valves on super heater and reheater attemperation lines are CLOSED.

-

UCB and local check.

-

BFP local operator intimated before starting of BFP.

-

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FEED WATER SYSTEM

BFP STARTING PROCEDURE WHEN BOTH PUMPS ARE OFF

ACTION 1.

2.

CHECK before starting any BFP.

START the boiler feed pump motor.

OBSERVATION - All pre-start checks are COMPLETED

- Local/UCB checks.

- All BFP permissive are ON.

- Associated saffron lamps are ON.

- Breaker closed indication comes on.

- Red indication ON.

- Motor takes starting current and then comes to no load current of 125 amps.approx. - BFP header discharge Pr. increases up to 85 Kg/cm 2.

- UCB check.

- Integral bypass valves of the BFP main discharge valve (FW-

KORBA SIMULATOR

REMARKS

- Associated red & green lamps are on - UCB indication.

22

101/FW102/FW-103) start opening. - After integral bypass valves are fully open, BFP main discharge valve starts opening Suction flow increases to 150 T/Hr. approximately.

3.

TRANSFER to manual & RAISE BFP scoop tube position to get desired feed water

- Interlock.

- UCB check.

- Motorised cooling water valve, (BCW-72/98/124 starts opening.

- Supplies cooling water to motor air box and working oil coolers.

- BFP aux. oil pump goes off as the main oil pump takes over.

- Interlock.

- Scoop control transfers to AUTO with a time delay of 5 secs.

- Interlock.

- BFP discharge pressure rises.

- If on auto BFP scoop tube can be operated through BFP master.

- Feed water flow through the BFP starts increasing above 150 T/Hr. - BFP header pr. low alarm gets reset.

- UCB indication.

- Re-circulation valve auto release becomes available, if BFP flow exceeds 150 T/Hr. 4.

OPEN feed regulating station low range controllers isolating valves

- Integral bypass valves of FW99/100, A and B open up.

- UCB indication

- Main Isolating valves of FW99/100 open up. 5.

ADJUST re-circulation flow set point to 30% and TRANSFER control to auto. KORBA SIMULATOR

- Re-circulation flow set point is provided above the recirculation valve controller.

- M/A releases push button for auto/ manual transfer. 23

- Re-circulation valve control transfers to auto. 6.

INSTRUCT Local operator to check bearing vibration and temperatures locally

- Various bearing temperatures and vibration limits are:

Alarm 95 oC

Brg. temp. Working oil outlet temp

Trip 105 oC 130 oC

95 oC 9 mm/sec.

Vibration Motor wdg temp.

110 oC

- Monitor Brg temp and vibration indicators.

DAS/Local indication.

12 mm/sec.

DAS/local point.

135 oC

WHEN ONE PUMP IS RUNNING

1.

ACTION

CHECKS before starting the second BFP.

-

START the BFP motor


-

UCB/local check,

All BFP start Permissive is AVAILABLE.

-

UCB check only.

-

BFP main discharge valve OPEN.

-

UCB check only.

-

Aux. oil pump is ON and lub oil pressure is ADEQUATE.

-

IF not, start the AOP.

-

BFP scoop tube position is MINIMUM BFP selector switch is on NORMAL.

-

UCB indication.

-

UCB check.

-

Breaker closed indication comes on.

-

UCB indication.

-

BFP scoop tube controller transfers to auto and follows master controller output.

-

Interlock. UCB indication.

-

Interlock. UCB indication

-

Interlock.

-

Motorised cooling water valve, (BCW-72/98/124) open up. - BFP aux. oil pump trips KORBA SIMULATOR

REMARKS

-

-

2.

OBSERVATION

24

automatically as the main oil pump takes over. 3.

ADJUST recirculation flow set point to 30% and TRANSFER control to auto.

-

Re-circulation flow control transfers to auto.

-

Re-circulation valve modulates to maintain set re-circulation flow.

-

Re- circulation valve control trips to manual & opens 100% if BFP flow drops below 130 T/Hr

4.

ADJUST scoops of the two running BFPs to equalise loads.

-

BFPs discharge pr. flow indications must become approx. equal.

-

UCB check only.

5.

ADJUST BFP bias to 50% and ADJUST BFP master controller equal to BFPs scoop tube position.

-

BFP biasing set has been provided above BFP scoop control.

-

M/A release must be pressed for auto/manual transfers

-

Controller error on the scoop controls of the running BFPs becomes zero. BFPs scoop controls transfer to auto.

-

UCB indication Maintain DP across 2 FRS 6-8 Kg/cm .

-

UCB M/A release push button is to be pressed for auto/ manual changeovers.

-

BFP master trips to manual if any of the running BFPs trips or individual BFP control is changed to manual mode.

6.

TRANSFER running BFP SCOOP control to auto.

-

7.

Adjust FRS DP, set to 60% -80% and TRANSFER BFP master control to auto.

-

KORBA SIMULATOR

Controller error on BFP master Controller becomes zero, when actual& set values of DP are matching

25

BFP SHUTDOWN PROCEDURE

1.

ACTION

TRANSFER scoop control of the BFP to manual.

OBSERVATION

REMARKS

-

Scoop control transfers to manual.

-

UCB indication.

-

BFP master also transfers to manual.

-

UCB indication.

2.

REDUCE scoop tube controller of the BFP to minimum position.

-

BFP discharge pressure and flow start decreasing

-

If needed, start the standby BFP, or reduce unit load to 80 MW - 100 MW.

3.

STOP the BFP motor.

-

BFP motor breaker opens.

-

Associated green lamp comes on.

-

BFP re-circulation valve opens 100%

-

UCB indication.

-

Motorised cooling water valve starts closing.

UCB check only.

-

If no other BFP is in service the discharge valves of all BFPs start closing.

Interlock.

4.

-

Close the BFP suction valve and rack out breaker if any maintenance to be carried out.

NOTE:-

Before closing the suction valve, please ensure that discharge valve is closed & there is no passing in the discharge valve and NRV. Otherwise, due to back pressurising booster pump glands may fail, leading to leakages etc. Watch for any increase in suction pressure when closing suction valve.

KORBA SIMULATOR

26

SINGLE ELEMENT FEEDWATER CONTROL

THREE ELEMENT FEEDWATER CONTROL

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BOILER SYSTEM

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KORBA SIMULATOR

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AUXILIARY PRDS CHARGING ACTION 1.

CHECK these conditions are satisfied before charging the aux. steam header.

OBSERVATION -

Station start-up boiler has been started already.

-

Aux. steam isolating valve S-16 and its bypass from aux. boiler side are CLOSED.

-

The entire header drains DW-238/239 DW-178 /179, DW-182 /183, DW-186/187 and DW190/191 on the station header are OPEN fully.

-

Station header inlet vlv AS-3 is OPEN 100%.

-

All the unit aux. header drains and vents DW194/195 are OPEN.

-

3.

OPEN-UP AS-31 fully to charge unit aux. header.

Unit interconnecting valve AS-31 to Unit-1 and/or other units are CLOSED.

REMARKS -

Refer to the operating instruction of the Aux. Boiler. Not simulated.

-

Not simulated. Local operation.

-

Not simulated.

-

UCB operation.

-

Valve AS-10, Unit PRDS connection to unit header, is CLOSED.

-


-

All header drains can be closed after charging the header.

-

Local operation.

-

Unit aux. header pressure increases up to 15 Kg/cm2 and '' aux.

-

UCB indications

-

Local check only. Not simulated.

steam pressure low'' alarm clears off. 4.

ENSURE all the conditions are satisfied before charging the unit PRDS system.

KORBA SIMULATOR

Oil tank level is ADEQUATE & oil pump is RUNNING and its pressure is ADEQUATE.

30

-

All hydraulic valves' controls are on REMOTE.

-

Local operation/check. Not simulated.

-

Isolating valve AS-6 and AS-9 are OPEN 100%

-


-

Isolating vlv AS-4 and AS-7 are CLOSED fully.

-

UCB check.

-

Main steam pressure is 2 more than 50 Kg/cm .

-

UCB check. Interlock for opening AS-4/7.

-

All iso. valves on F.W. line for de-superheating are OPEN 100%.

-

Not simulated.

-

Steam pressure and temperature set points

-

UCB operation.

2

at 14 Kg/cm and 220 deg. C., respectively. 5.

OPEN AS-4 and AS-7 from the UCB to charge unit PRDS header.

-

Integral isolating valves 4A and 7A open-up and then AS-4/7 start opening

-

UCB operation.

6.

OPEN AS-10 fully and PRDS pressure controller gradually and transfer control to auto.

-

PRDS-1 (30% line) starts opening.

-

UCB indication

-

Temp controller transfers to auto to maintain set temp after de-super heater

-

UCB indication.

-

Spray pressure controller maintains feed water pressure at 2 20 Kg/cm (for 30% line) PRDS-2 starts opening after a certain controller output.

UCB check only.

-

-

7.

CLOSE AS-31 after unit PRDS is fully charged.

KORBA SIMULATOR

Interlock

Spray pressure set point 2 ramps up to 40 Kg/cm (for 100% line)

Auto interlock.

PRDS header pressure is to be maintained at 14 Kg/cm2

At 300 deg. C all PRDS valves are trip closed.

-

31

HEAVY FUEL OIL SYSTEM In coal fired Thermal Power Plants, the Fuel Oil plays a vital role in initial firing of the Boilers and running it up to 25-30% of its capacity. The fuel oil is also used as a stabilising fuel in the coal fired boilers till the coal flame stabilises in the furnace and for proper coal burning while the load is reduced in the boiler for a shut down. All the main storage tanks are generally interconnected to the suction side of unloading pumps so that oil from one tank can be transferred to another for the purpose of any maintenance work. The storage tanks are equipped with Magnetic type float switches and Mechanical type float level Indicators to measure the quantity of oil stored. In order to keep the viscosity of oil in storage tank low, it is essential to keep the oil warm between 50 0C to 70 0C so that the oil from main tanks can be transferred to service tanks for normal / daily utilisation of fuel oil for the firing. For this purpose a steam floor-heating coil has been laid at the bottom of the tank. Thermostatic temperature controller installed at the inlet of steam heating coil, controls the temperature of oil tank at the desired point selected between 50 0C to 700C. The HFO passes through the oil strainer on the suction side of the high-pressure screw pump. Heavy oil pumping unit consists of oil suction strainers and screw pumps each coupled through flexible coupling and mounted on a common frame.

HEAVY FUEL OIL SYSTEM KORBA SIMULATOR

32

The screw pump, when connected to an induction motor with constant speed, is a constant quantity pump and valves in the delivery line control the delivery pressure. When only a small quantity of oil is fired, the excess oil from the pump discharge should be bypassed. This is done automatically by electrically operated, pressure maintaining valve bypassing the excess quantity through the return oil line to storage tank and the delivery pressure of oil is maintained constant at the pump outlet, whatever be the quantity of fuel oil. HFO from the delivery side of the HFO pumping unit enters the HFO pre-heater where it is heated from pumping temperature to a temperature corresponding to an atomising viscosity. The outlet temperature of HFO from the heat exchanger is automatically maintained at a constant value by the automatic temperatureregulating valve, mounted on the steam supply line to heaters. The temperatureregulating valve controls the quantity of steam to the heater according to the outlet temperature of the oil from the heater.

H.F.O STORAGE TANKS: 2500 M3 each

3 Numbers, Capacity:

H.F.O. Pressuring Pump: 3 Numbers, Type: Motor Rating

Triple screw type, Bornemann 50 KW, 415 V, 3 ph., 50 Hz

Power Required

32 KW at 370 cst.

Capacity

430 litres / min. at 370 cst.

KORBA SIMULATOR

33

FURNACE SAFEGUARD AND SUPERVISORY SYSTEM FSSS facilitates remote manual/automatic control of fuel firing equipments through mechanised system with suitable interlocks and logics. It is designed to ensure the execution of a safe, orderly operating sequence in start up and shutdown of fuel firing equipments, and thereby to prevent errors or omissions in following such procedure. The system provides protection against malfunction of fuel firing equipments and associated air system. The safety feature of system is designed for protection in most common emergency situations. FSSS comprises of control circuits, various logics and indicators to carry out the following: • To start furnace purge when all technological conditions are fulfilled. • To start and monitor the Ignitors. •

HFO Gun starting, stopping and supervision.

•

Pulveriser and Feeder starting, stopping and supervision.

•

Flame Scanner intelligence and checking.

•

Furnace flame monitoring and overall furnace flame failure protection.

• To trip out all boiler fires when boiler safety is threatened. • To start/stop ignitor and scanner air fans. • To regulate the Secondary Air Dampers depending upon the fuel flow variation. • To provide boiler trip signal to other system such as PA Fan, Mills, Turbine, Generator etc. FSSS

equipments can be grouped under three heads:

1. The Operating and Indicating Console Insert in UCB: This consists of all switches for initiating controls and also indications of status of all fuel firing equipment & their auxiliaries. 2. Relay and Logic Cabinets: The cabinets consist of relays, timers, programmers, circuit breakers for AC and DC control supplies flame scanner unit, number of coal flow units etc. They control the process logic. 3. Field Equipment: Field equipments are those which help in actual remote operation of fuel firing equipments and those, which provide the status to the operating, console and relay logic cabinet. KORBA SIMULATOR

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Field Equipment Includes: Ignitor/HFO Trip Valves, HFO atomising steam, Scavenging steam/ Nozzle valves (Hydra motor type), gun advance/retract mechanisms, oil gun assembly, ignitors and its cabinets, flame scanner and ignitor air fans, pressure switches, temperature switches, flow switches and limit switches, Mill Discharge valves, hot air gates, seal air valves, cold air, tramp iron gate etc. FSSS POWERSUPPLY ARRANGEMENT

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220 V AC SUPPLY SYSTEM 1.

ANALOGUE CONTROL SYSTEM (ACS) : (H&B)

2.

ANNUNCIATION

3.

AUX. PRDS :(SULZER)

4.

AUX. RELAY PANEL

5.

DATA ACQUISITION SYSTEM (DAS)

6.

FEEDER CABINET

7.

FSSS AC SUPPLY

8.

HP BYPASS CABINET: (SULZER)

9.

HYDRASTEP

10. SECONDARY AIR DAMPER CONTROL (SADC)

110 V AC SUPPLY SYSTEM 1.

ATOMISING STEAM NOZZLE VALVES

2.

FLAME SCANNER MODULE

3.

HFO NOZZLE VALVE MOTOR

4.

IGNITOR FAN DISCHARGE DAMPER

5.

LAMP INDICATION + LOGIC POWER

6.

MILL DISCHARGE VALVE

7.

MILL FEEDER CONTROL

8.

MILL SEAL AIR DAMPER

9.

SCAVENGE STEAM NOZZLE VALVE MOTOR

10. SEAL AIR FAN DISCHARGE DAMPER

220 V DC SUPPLY SYSTEM 1.

HFO TRIP VALVE

2.

HFO RE-CIRCULATION VALVE

3.

IGNITOR OIL TRIP VALVE

4.

MILL MOTOR CONTROL

5.

SCANNER FAN DISCHARGE DAMPER

6.

SCANNER FAN EMERGENCY SUCTION DAMPER

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FSSS LOGICS AND INTERLOCKS FURNACE PURGE Furnace purge is required after every boiler trip-out and before light up to expel all unburnt fuel particles, gases, vapour etc. from the boiler, so that possibilities of explosion are eliminated, when ignition energy is made available. Boiler purging cycle is of 5 minutes duartion. 'PURGE READY' appears only when all the purge permissives are satisfied. Pressing ‘PURGE START’ push button will start purging. When purge cycle is completed, 'PURGE COMPLETE' signal will come. This is an indication that boiler MFR is reset and now boiler can be lighted up. If any time during purging, any of the Purge Permissive conditions are violated, 'PURGE READY' signal will disappear, and purging cycle is to be started once again after establishing 'PURGE READY' conditions. Once purging is completed, boiler will trip if any of the 'Boiler Trip' conditions occur.

PURGE READY CONDITIONS The conditions to get Purge Ready are: 1.

No Boiler Trip

2.

Warm-up valves closed

3.

All auxiliary air dampers modulating and wind-box to furnace DP O.K.

4.

All feeders off.

5.

All elevation flame scanners show 'no flame'.

6. 7.

Both PA fans off. All ignitors and Warm-up Trip valves closed.

8.

Hot Air Gate closed.

9.

Ignitor Valves closed.

10. All pulverisers off. 11. Nozzle Tilt Horizontal AND Airflow less than 40%. IGNITOR TRIP VALVE INTERLOCK A)

Ignitor trip valves will open when trip valve 'open' Push Button is pressed provided all the following conditions are fulfilled: a. Ignitor oil supply pressure is adequate, more than 13 Kg/cm

2

b. All ignitor valves are closed c. No boiler trip command is persisting. d. Scanner air to wind box differential pressure more than 125 mm WCL. When ignitor trip valve is fully open, 'Open' signal comes on FSSS console. KORBA SIMULATOR

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B)

Ignitor trip valve will close under following conditions: a. 'Close' push button is pressed from console or b. Ignitor oil header pressure falls below 9 Kg/cm2 for more than 2 seconds AND any ignitor valve not closed. c. Boiler MFR trip command is present. When ignitor trip valve is closed, the valve ''closed'' green lamp comes on.

Ignitor Starting There is no separate ignitor start switch provided for any of the elevation AB, CD or EF Ignitors. Pressing any one pair of oil gun ' START' or STOP' push button gives a starting impulse to all four ignitors of that elevations. The spark is applied for 10 seconds only for every pressing of ignitor start push button. Ignitor Stopping All four ignitors of each elevation are provided with one 'STOP' push button for taking out ignitors from service. Also ignitor gets stop command, at the end of stop time trial of HFO oil elevation. When individual ignitors get stop command its motorised oil/air valve closes thus taking out ignitors from service. HEAVY OIL FIRING Heavy oil can be fired at AB, CD and EF elevation. Heavy oil gun have been programmed to light up on pair basis, diametrically opposite corners (1,3 and 2,4) form the pairs. Each pair is provided with start/stop push button. HFO guns can be lighted up only if at least 3 out of 4 ignitors at corresponding elevations are in service. HFO guns are self-sustaining only when elevation firing rate is at 30%, hence, ignitors corresponding to HFO guns in service must only be removed when HFO burner header pressure is above 3 Kg/cm2 (g) and at least 3 HFO guns at the elevation are in service and corresponding flame scanners are sensing flame. Flame scanners monitor heavy oil guns flame only when the following conditions are fulfilled. i. HFO firing rate (elevation load) is above 30%. ii. 3 or more HFO guns at the elevation. iii. Ignition energy removed.

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HFO TRIP VALVE INTERLOCK A. HFO Trip Valve (HOTV) can be opened by pressing 'OPEN' push button, provided the following conditions are fulfilled. a. Boiler Trip Command (MFR) is RESET, and b. All HFO nozzles of AB, CD and EF oil guns are proven fully closed. 2

c. HFO supply pressure is adequate (more than 16 Kg/cm ). O

d. HFO header temperature adequate (more than 95 C) OR

HFO recirculation valve is open 100% (Bypass conditions for all the above.)

B. HO trip valve closes under any of the following conditions: •

HFO header pressure is low (<3.5 Kg/cm 2)

•

HFO header temperature is low (< 95 0C)

OR OR

• Atomising steam pressure is low (<7.5 Kg/cm 2.) AND all HFO nozzle valves not closed. OR A boiler trip occurs, OR •

HFO trip valve 'CLOSE' P.B. is pressed, when HFO trip valve is fully closed, valve 'CLOSED' green light appears.

HFO Re-circulation Valve Interlock Opening: HFO re-circulation valve can be opened following a boiler trip and before starting furnace purge cycle by pressing valve 'open' push button. Valve opens provided: a. All of the HFO nozzle valves are fully closed, and b.

Re-circulation Valve ' OPEN' command is given.

Closing: HFO re-circulation valve closes automatically when anyone of the nozzle valves (Hydra motor) is not closed, or manual ' CLOSE' command is given. Heavy Oil Gun Elevation Start Permissive: a. b.

D.C. power available Ignitor trip valve is proven fully open.

c.

No boiler trip command persists.

d.

HFO trip valve is proven fully open.

e.

Heavy oil temperature above 100 oC.

f.

Airflow adjusted between 30% and 40% of full load airflow.

g.

Burner tilt placed in horizontal position.

The last two conditions are not required if any one feeder is PROVEN. KORBA SIMULATOR

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HFO Corner Start Permissive At each main oil corner to be placed in service, following conditions should be satisfied:a. b.

The main oil guns are inserted in guide pipe and coupled. The local maintenance control switch is placed in REMOTE.

c.

HFO manual isolation valve is open.

d.

Atomising steam manual isolation valve is open.

e.

Scavenging steam valve is closed.

f.

'Elevation Start' Permissive available

HFO Gun Starting Sequence When HFO Pair start push button is pressed a pair of HFO guns is placed in service in following sequence (provided HFO elevation start premissives are satisfied). • Within first 10 seconds of pair start trial time associated elevation ignitors are started. When ignitors are proven, Ignitor 'ON' signal comes on. If the flame is not proven, sparkwill cease and Jamesbury Valve is closed after 10 seconds. • When minimum 3 out of 4 ignitors at the associated elevation are proven ‘ON’ at the end of 10 seconds, a start command is given to heavy oil gun no. 1 (if pair 1 - 3 is selected) or to heavy oil gun no. 2 (if pair 2 - 4 is selected), if cornerscavenging valve is closed. • Twenty five seconds later a start command is sent to corner no 3 (in case of 1 3 pair) or corner no. 4 (in case of 2 - 4 pair) When an individual heavy oil corner receives a 'start' command and its associated ignitor is proven 'ON' it is placed in service in following sequence. a.

Heavy Oil gun advances to firing position. 'Gun Retracted' lamp goes out and 'ADVANCE' light glows.

b.

When the gun is fully advanced, the atomising steam valve opens.

c.

When the atomising steam valve is proven fully open, the heavy oil nozzle valve opens placing the HFO gun in service.

All ignitors can be removed by pressing Ignitor Stop push button. -

3 out of 4 HFO nozzle valves are proven open.

-

Elevation loading is about 30%.

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-

Minimum 3 out of 4 flame scanners sensing flame at that elevation.

Unsuccessful Corner Start: At the end of 90 seconds of pair start trial time a heavy oil corner trip is initiated for any corner when a. Heavy oil nozzle valve is not proven fully open. b. Associated ignitor is not proven 'ON'. Heavy oil Elevation Shutdown Heavy oil elevation is removed from service on a pair basis. Depressing the associated elevation pair stop P.B. will initiate a 375 sec. time trial to shutdown and scavenge the associated pair of heavy oil guns as follows: a.

During first 10 seconds of stop time trial associated elevation of ignitors is started.

b.

At the end of start time a stop command is sent to corner no. 1 (when pair 1 & 3 is stopped) or corner no. 2 (when pair 2 & 4 is stopped).

c.

Fifteen seconds later, a stop command is sent to corner no. 3 (when pair 1 & 3 stopped) or corner no. 4 (when pair 2 & 4 is stopped).

When an individual heavy oil gun that is in service, receives a stop command: a.

A scavenge command for that corner is initiated and HFO nozzle valve closes. The atomising steam valve remains open.

b.

When the HFO valve is proven fully closed and if the associated ignitor is proven ON and the atomising steam valve has remained open, the scavenge valve opens.

c.

When the scavenge valve is proven fully open, a five minute scavenge period is started.

d.

At the end of 5 minutes scavenge period, the atomising steam valve close.

e.

When both the valves are proven fully closed, the HFO gun is retracted from firing position.

Six minutes after, remaining pair of HFO guns stop is initiated, a back-up trip

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signal is established which will remove the associated elevation of ignitors from service and initiate a close signal to all HFO nozzle valves, all of the scavenge valves at the elevation to ensure they are closed. Fifteen seconds later an 'Unsuccessful Elevation Shut-down' alarm comes if – a.

b.

Any HFO gun is not retracted from firing position at any elevation, OR Any HFO nozzle valve is not closed at any elevation.

PULVERISER INTERLOCKS Pulveriser Ready Permits At the respective Pulveriser, all of the following conditions are to be satisfied: 1.

Start Permit.

2.

Pulveriser discharge valve open.

3.

Seal air O.K.

4.

Cold air gate open.

5.

Pulveriser outlet temperature less than 200 o F.

6.

Primary air permit.

7.

No Pulveriser trip.

8.

Feeder local selector switch is on REMOTE.

9.

No unsuccessful start.

10. Tramp iron hopper valve open. When all the above conditions are satisfied for the respective Pulveriser, its associated 'Pulveriser Ready' light appears. Availability of Ignition Permit for Pulveriser Operation:Prior to starting any Pulveriser, ignition energy must be adequate to support coal firing. This is accomplished as follows: Pulveriser-A i.

ii.

A minimum 3 out of 4 elevation AB heavy oil nozzle valves proven open. OR Boiler loading is greater than 30% and feeder B is in service at greater than 50% loading.

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Pulveriser-B i.

A minimum 3 out of 4 elevation AB heavy oil nozzle valves open, OR

ii.

Boiler loading is greater than 30% and feeder A or C is in service at greater than 50% loading.

Pulveriser - C i.

A minimum 3 out of 4 elevation CD heavy oil nozzle valves proven open. OR

ii.

Boiler loading is greater than 30% and feeder B or D is in service at greater than 50% loading. OR

iii.

A minimum 3 out of 4 elevation AB heavy oil nozzle valves proven open and feeder B is in service at greater than 50% loading.

Pulveriser - D i.

ii.

A minimum 3 out of 4 elevation CD heavy oil nozzle valves proven open. OR Boiler loading is greater than 30% and feeder C or E is in service at greater than 50% loading.

Pulveriser - E i.

A minimum 3 out of 4 elevation EF heavy oil nozzle valves proven open. OR

ii.

Boiler loading is greater than 30% and feeder D or F is in service at greater than 50% loading. OR

iii.

A minimum 3 out of 4 elevation CD heavy oil nozzle valves proven and feeder-D is in service at greater than 50% loading.

Pulveriser - F i.

A minimum 3 out of 4 elevation EF heavy oil nozzle valves proven open. OR

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ii.

Boiler loading is greater than 30 % and feeder-E is in service and greater than 50 % loading.

Condition (i) is not required if any coal feeder is already 'PROVEN'

Pulveriser Start When both ''Ignition Permit'' and 'Pulveriser Ready' are established for the respective Pulveriser, the Pulveriser may be placed in service as follows: •

Start the Pulveriser by depressing its associated push button.

• When the Pulveriser is proven ON as indicated by its (red) indication open the hot air gate by pressing its open push button and allowing the Pulveriser outlet temperature to come up to more than 60 oC. Adjusting Hot/Cold air controlling dampers does this. • When the Pulveriser temperature comes up to (Approx. 60-90oC) start the feeder by depressing its associated START push button (associated elevation of fuel air dampers should be closed for feeder starting). Coal flow must be proven either by the coal flow detector or satisfactory Pulveriser amps within five seconds after the feeder is started. Fifteen seconds after the feeder is started, the feeder output is released to automatic control, and the fuel air damper is opened to modulate as a function of feeder speed. When a minimum of two feeders are established at greater than 50% load the associated elevation of oil guns may be shutdown provided the feeder has been on for a minimum of three minutes. Feeder Start Permissive and Interlocks a. Feeder speed minimum (controller position less than 20%). b. Pulveriser 'ON' and its outlet temperature more than 55 oC. c. All Pulveriser ready conditions as mentioned above are satisfied. d. Coal silo gate open (Operator check only). Feeder Interlocks. Either of the following conditions will force the feeder speed to manual and minimum until the initiating condition is corrected. i). Pulveriser bowl differential pressure high (>250 mm WCL) ii). Pulveriser grinding current above 38 Amperes. Loss of coal flow and low Pulveriser power as confirmed by Pulveriser amps will trip the feeder. Any Pulveriser trip shall trip the associated feeder instantly.

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Hot/Cold Air Dampers and Hot Air Gate Interlocks 

All cold air dampers (CADs) will close to less than 5% open when the START command is given to any PA Fan if no PA fan is running.



All CADs shall open 100% if boiler trips.



When the start command is given to any Pulveriser, the associated cold air damper is open 100%.



When any Pulveriser outlet temperature is more than 95oC the CAD is open 100% and HAD is closed 100%.



Operation release for the CAD is obtained when the associated HAG (hot air gate) is opened 100%.



The HAG can be opened manually when the associated Pulveriser is 'ON'. or it can be opened automatically when Pulveriser on command is given on 'AUTO'.



HAG of any Pulveriser will close if the temperature at outlet of Pulveriser is more than 95oC or the associated feeder trips with a time delay of 40 sec.



The HAG will close instantaneously if the associated Pulveriser trips from service.

PULVERISER TRIP CONDITIONS The following conditions will initiate a Pulveriser trip command: •

Pulveriser discharge valve not open.

•

Loss of unit critical power for more than 2 seconds.

•

Pulveriser ignition permit is not available or lost when supporting ignition is required if the feeder is 'on' for less than 3 min.

•

Boiler MFR trip.

•

Primary air header pressure very low (< 585 mm wcl).

Note: 1. When both PA fans are tripped or hot PA pr. falls below the low set point of 585 mm wcl all pulverisers in service receive a tri p command with a time delay of 5 seconds. When hot primary air duct pressure falls below very low set point of 525 mm WCL, all pulverisers in service are tripped instantaneously. 2. When only one PA fan trips or stopped and four or more pulverisers are in service, a trip command will be initiated to trip the running Pulveriser from the top until the number of pulverisers running is reduced to three.

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BOILER TRIP CONDITIONS (200MW) FSSS protects the boiler by trippingout all fuel inputs, under the following conditions 1.

Simulate Trip.

2.

Loss of 220V DC to FSSS.

3.

Elevation Power Failure.

4.

Flame failure.

5.

Loss of all fuel.

6.

Airflow falls below 30% (MCR).

7.

Furnace pressure high (+ 200 mm WCL).

8.

Furnace pressure low (- 200 mm WCL).

9.

Drum level high (+ 225 mm).

10.

Drum level low (-225 mm).

11.

Re-heater protection trip.

12.

Turbine Trip with boiler load more than HP/LP Bypass capacity (60%).

13.

Loss of all Boiler Feed Pumps.

14.

Both Emergency Push Buttons pressed.

15.

Loss of ACS Power.

16.

Loss of Unit Critical Power.

17.

Both FD Fans OFF.

18.

Both ID Fans OFF.

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STEPWISE OPERATION LOGICS OF F.S.S.S. (200 MW) 1.

PURGE PERMISSIVE & PURGE COMPLETE

2.

IGNITOR WARM-UP & RE-CIRCULATION FUEL TRIP VALE

3.

IGNITOR FAN AND OUTLET DAMPER CONTROL

4.

SCANNER AIR FAN CONTROL

5.

WARM-UP ELEVATION START PERMIT

6.

PAIR 1-3 AND 2-4 WARM-UP ELEVATION CONTROL

7.

SELECTION OF OPERATION MODE

8.

OPERATION IN ELEVATION MODE

9.

WARM-UP ELEVATION IGNITOR CONTROL

10.

WARM-UP ELEVATION CORNER NOZZLE CONTROL

11.

PULVERISER READY

12.

PULVERISER TRIP

13.

COAL ELEVATION PULVERISER CONTROL

14.

PULVERISER SEAL AIR VALVE & DISCHARGE VALVE CONTROL

15.

FEEDER CONTROL

16.

AUTO CLOSE COMMAND FOR HOT AIR GATE

17.

HOT AIR GATE CONTROL

18.

COLD AIR DAMPER CONTROL

19.

MILL FEEDER SPEED DEMAND TO MINIMUM

20.

MILL FEEDER PROVEN SIGNAL

21.

RELEASE FOR AIR AND TEMP. CONTROL TO AUTO

22.

PULVERISER IGNITION PERMIT A & F

23.

PULVERISER IGNITION PERMIT B & E

24.

PULVERISER IGNITION PERMIT C & D

25.

CONTROL OF SEAL AIR FAN

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OPERATION PROCEDURE AIR PRE-HEATER OPERATION PRE-START CHECKS OBSERVATION

ACTION 1

CHECK all the pre-start conditions are satisfied.

-

-

REMARKS

Support bearing/ guide bearing lub oil pumps RUNNING and lub oil coolers are CHARGED. Bearing temperature NOT HIGH (less than 60oC) is

-

Associated red lamp is on

-

Ascertain from local operator.

-

If not, line-up air motors. Local operation.

-

Electrical supply AVAILABLE.

-

Isolating valves of air motors are 'OPEN' and bypass valves of air motor solenoids are 'CLOSED'.

-


-

'Air motors' lub oil level ADEQUATE

-

Local check.

-

Service air pressure is

-

Local/UCB check.

ADEQUATE (> 5 Kg/cm 2)

APH STARTING PROCEDURE WHEN BOTH APHS ARE OFF

ACTION 1

2

START air motors of both APHs.

OBSERVATION

REMARKS

-

Air motors ON indications come on

-

Corresponding red lamp glow.

-

Isolating dampers of APHs start opening.

-

UCB indications.

Breaker CLOSED indication comes on

-

UCB indication.

Associated air motor stops.

-

UCB indication.

START air heater electrical motor. -

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3

INSTRUCT local operator to check, locally, for any abnormal sounds from bearings/seals.

-

Starting current shoots up and comes down to normal load current.

-

UCB indication.

-

Isolating dampers of the air heater remain open.

-

Associated red lamps on.

-

Isolating dampers of the other air heater, not in service, start closing if its air motor is not ON.

-

Associated green lamps come on.

-

There should be no abnormal hunting in air heater amperes meter readings.

-

UCB check.

-

There should be no abnormal sounds from air pre-heater seals or bearings.

-

Local check.

-

Bearing temperatures must be within the normal range (65 oC -75 oC)

-

UCB OMNIGUARD indicators must be frequently monitored.

Note: Air pre-heaters air motors can be started manually provided electrical motors are off, isolating valves of air motor solenoid are open and service air pressure is normal. The air motors come into service on auto interlock, when corresponding electrical motors trip-out on any protection.

WHEN ONE APH IS RUNNING 1

ACTION

CHECK before starting any APH.

-

-

-

KORBA SIMULATOR

OBSERVATION

All pre-start checks are COMPLETED.

-

Support bearing / guide bearing lub oil pumps are ON. Bearing temperature NOT HIGH (< 60 oC) and lub oil coolers are CHARGED

-

REMARKS Local/UCB.

Corresponding red lamps ON.

Ascertain from local operator.

75

-

-

Electrical supply is AVAILABLE Air motor is ON All isolating dampers of the air pre-heater are OPEN.

2

3

START air preheater electrical motor.

-

Refer to the respective modules.

-

UCB check only.

-

Red lamps on.

-

Breaker CLOSED indication comes on.

-

Red lamp on.

-

Starting current goes up and comes down to normal load current

-

UCB/Local check.

-

Air motor goes off.

-

UCB indication Interlock.

-

Air heater isolating dampers remain open.

-

UCB check.

INSTRUCT local operator to check for healthy running of air heater.

There should be no ABNORMAL hunting of ampere reading.

UCB indication.

There should be no abnormal sounds from air pre-heater seals/ bearings.

Local checks.

The bearing temperatures must be within the normal range (60 oC to 75 oC).

UCB OMNIGUARD indicators must be checked for bearing temp frequently.

SHUT DOWN PROCEDURE

ACTION 1

CHECK

2

UNLOAD associated ID/FD fans, gradually.

OBSERVATION

-

KORBA SIMULATOR

Corresponding ID& FD Fans are running. The other pair of ID/FD fans (if running) starts loading up on auto.

REMARKS

-

Associated breaker closed indication are on. Operator's action, if fan controls are on manual.

76

3

STOP the associated FD fan.

-

Fan breaker goes open.

-

Maintain desired oxygen percentage.

-

Furnace total airflow indication drops slightly.

-

Reduce firing if required.

4

STOP the associated ID fan.

-

Furnace pressure increases slightly.

-

Maintain furnace draft between-5 to - 10 mm wcl.

5

STOP air heater electrical motor.

-

Air heater electrical motor goes off.

-

Breaker off green lamp comes on

-

With a few seconds time delay, the isolating dampers of the air heater are closed, if the other AIR HEATER is in service.

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Associated green lamps come on.

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ID FAN OPERATION PRE-START CHECKS OBSERVATION

ACTION 1

2.

CHECK all the start permissive are satisfied before starting the ID Fan.

CHECK if the fan is lined-up for operation.

-

REMARKS

Fan lub oil pressure is

-

If not, ask the local operator to start the lub oil pump and check the pressure.

ADEQUATE (1.2 Kg/cm2).

-

Fan inlet/outlet dampers (GD 17/18, GD 21/22 is CLOSED.

-

The dampers start closing after the first fan start command is given.

-

Fan inlet guide vanes are at MINIMUM position.

-

This permissive is fulfilled after the first fan start command is given.

-

Fan bearing temperature is NOT HIGH (< 60 oC .)

-

Local/UCB check. Fan start permissive. are available.

-

Local operation/check. Boiler VDDC / MCC panels to be checked.

-


-


-

-

-

Electrical supply for various motor operated dampers is ON. Lub oil system is lined up and water/oil coolers are CHARGED. Oil level in the tank is ADEQUATE.

-

Anyone or both are ON.

APH

-

UCB check. Interlock.

-

EPBs are in RELEASED position.

-

Local operation/check

-

Inlet guide vanes are 100% open when both ID fans are off.

-

Local check. IGVs are OPERATIONAL and ON REMOTE

-

Instrument air pressure is ADEQUATE.

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3

CHECK if flue gas path is LINED-UP for ID Fan operation.

-

ID fans' suction/ discharge dampers are OPEN 100% and operational.

-

Manual isolating dampers on suction / discharge ducts of ID fans (GD19/20/23/24) are OPEN.

-

-

Sealing/flushing water supply for ESPs, economiser, APHs and bottom ash hoppers is AVAILABLE.

Local check.


-


-

Gas isolation dampers for ESPs and APHs are open.

-

UCB indications.

-

Changeover dampers GD5/6 before ESPs are OPEN.

-

UCB indication

-

Changeover dampers after ESPs (GD-15/16) are operational and CLOSED.

Local check. UCB indication and interlock.

-

Gas path is through for starting ID fan. (ESPs) A & B isolation dampers, APH A gas and secondary air isolation dampers are OPEN. OR ESPs C & D isolation dampers + APHB gas isolation dampers are OPEN. OR APH-B gas isolation dampers+ ESPs A&B isolation dampers + GD-5 and GD-6 are OPEN.

For ID Fan-A gas path clear interlock.

-

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ID Fan breaker is SERVICE/REMOTE position.

on -

Gas path ready conditions for ID Fan-B can be found out by symmetry

Local operation.

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STARTING PROCEDURE WHEN BOTH THE FANS ARE OFF 1

2

ACTION

Check before starting ID Fan.

START fan.

OBSERVATION -


-

All permissive for the fan AVAILABLE.

-

Local operator is informed before the fan is started.

-

-

''Inlet guide vanes min.'' & Inlet/outlet dampers closed'' permissive become available after the fan start command is given.

Inlet/outlet dampers start closing

-

UCB indication.

-

Inlet vanes come to minimum.

-

Controller output minimum.

-

The fan breaker is CLOSED after inlet/outlet dampers close fully. Starting current goes up to 500A and comes down to no load current of 45 A.

-

Breaker closed red indication comes on.

-

UCB indication.

-

Change-over dampers (GD-15, GD-16 start opening. (After fan starts).

-

Corresponding red lamps come on.

-

Inlet/outlet dampers open up.

-

UCB indication.

-

Inlet/outlet dampers of - Associated green the other fan go closed lamps on & controller and regulating vanes go position of IGV to minimum position. becomes zero.

-

Fan amperes go up with

-

3

ADJUST inlet guide

KORBA SIMULATOR

REMARKS

-

UCB indication.

80

vanes to maintain furnace draught between - 5 mm. to 10 mm.

4

INSTRUCT the local operator to check for abnormal bearing vibration and temperature.

vane position increasing (Controller output increasing).

-

Furnace draft starts improving.

-

Furnace airflow indication increases slightly.

-

-

UCB indication for furnace pressure moves down below zero.

Bearing vibrations must be within 40-50 micron.

-

Bearing temperatures should be below 85 oC (Alarm) or 105 oC (Trip).

UCB indications.

-

UCB OMNIGUARD or DAS indications.

WHEN ONE FAN IS RUNNING 1

ACTION

CHECK before starting the ID Fan.

OBSERVATION

REMARKS

-


-

UCB/Local checks.

-

Lub oil motor On. Lub oil pressure ADEQUATE

-

Associated red & saffron lamps on.

2

(>1.2 Kg/cm )

KORBA SIMULATOR

-

Xover dampers GD-15, GD-16 are OPEN.

-

UCB check only.

-

Regulating vanes are at MINIMUM position.

-

Controller output zero (minimum).

-

Inlet/outlet dampers are CLOSED.

-

Green lamp on.

-

Both APH s are ON.

-

Interlock.

-

Bearing temperatures are NORMAL (<60 oC )

-

Permissive.

81

2

3

4

START fan motor

REGULATE fan vanes to equalise load on both the fans.

CHECK locally & in UCB the brg temperature and vibration level.

-

Fan motor current settles down at 45A.

-

Breaker closed indication comes on.

-

Inlet/outlet dampers start opening.

-


-

GD-15 and GD-16 get closed.

-

Interlock.

-

Maintain furnace draft -5 mm wcl.

-

As per the boiler load.

-

Maintain desired airflow.

-

Bearing temperature limits are Alarm Trip

-

UCB OMNIGUARD indicators may be checked.

Alarm

5

6

ADJUST bias to 50% and furnace draught set point to 45%.

TRANSFER vane controllers of both fans to ''AUTO''.

KORBA SIMULATOR

Trip

Fan

95 oC

105 oC

Motor

75 oC

80 oC

-

Furnace draught set point and biasing set points have been provided above Fan-A & Fan-B vane controls respectively.

-

Operator action.

-

Check furnace draught is maintained between 5 mm wcl to-10 mm wcl.

-

UCB checks.

-

Vane controllers transfer to AUTO

-

UCB INDICATION

-

Inlet vanes modulate to maintain set value of furnace draught.

-

Furnace draft high alarm at + 50 mm & low alarm at -50 mm.

82

SHUT DOWN PROCEDURE

ACTION

OBSERVATION

REMARKS

1

SELECT IGV controls of both fans to manual.

-

IGVs control transfers to manual.

2

REGULATE IGVs of the ID Fan to minimum.

-

ID fan discharge pressure decreases.

-

ID fan current come to minimum load current of 45 amps.

-

The flue gas after EP interconnecting dampers open on interlock.

-


-

Total airflow drops slightly avoid Boiler trip

-

Maintain airflow more than 30%.

-

The inlet and outlet dampers close on interlock.

-

UCB indication.

-

Maintain furnace draught at -5 mm wcl.

-

-

Maintain desired amount of oxygen percentage.

-

Motor winding temperature limits are

3

4

5

STOP the ID fan.

REGULATE the inlet guide vanes of the running ID fan to desired loading.

CHECK the motor winding temperature of the running ID fan

Normal Trip Note :

-

M/A release push button must be pressed for auto manual changeover. - Maintain furnace draught at -5 mm wcl by loading the other ID fan.

-

If the need be, reduce boiler firing to approx. 50% to maintain furnace draught & prevent running ID fan over-loading.

DAS indication

100 0C 130 0C

If associated FD fan is in service it will be necessary to unload FD fan and stop it before stopping ID fan; to avoid airflow fluctuations (Refer to FD fan shutdown procedures). With ID fan being stopped corresponding FD fan will also trip.

KORBA SIMULATOR

83

FD FAN OPERATION PRE START CHECKS 1

2

3

ACTION

CHECK before starting the FD fan, all start permissive is satisfied.

CHECK if FD fan is lined up locally for starting.

CHECK if secondary air system is lined-up before starting FD fan.

KORBA SIMULATOR

OBSERVATION

REMARKS

- Fan control oil temp is NORMAL (<55 oC)

-

UCB/local check.

- Fan blade pitch is MINIMUM and Discharge damper is CLOSED

-

This permissive is satisfied after the first fan start command is given.

- Fan control / lub oil pressure is ADEQUATE.

-

UCB indication and Local operation

- Fan bearing temperature is NOT HIGH (<60 0C.)

-

UCB/local check.

- Fan lub oil system is LINED UP and oil coolers are charged.

-

Local check /operation.

- Lub oil tank level is ADEQUATE.

-

Local check.

- Anyone LOP is ON and other one are on AUTO.

-

Local operation.

- Fan EPBs are in RELEASED position.

-

Local operation.

- FD fan discharge dampers are OPEN 100%.

-

UCB check.

- FD fan blade pitch controller is OPERATIONAL and is on REMOTE. Instrument air pressure is AVAILABLE. - Any or both ID fans: ON

-

Local check/operation.

-

Interlock. UCB check.

- APHs' secondary air isolating dampers are OPEN.

-

UCB check/indication.

- SCAPH is available

-

Local operation/check.

84

- FD fan discharge dampers are OPERATIONAL and electrical supplies are AVAILABLE.

-

UCB checks.

STARTING PROCEDURE WHEN BOTH THE FANS ARE OFF



1

ACTION

CHECK before starting FD Fan.

OBSERVATION

- All pre-start checks are OVER.

REMARKS

-

"Blade pitch minimum" and "Discharge damper closed" permissive are available after the fan start command is given

- Discharge dampers start closing

-

UCB indication.

- Blade pitch comes to minimum.

-

Controller output 0%.

- As soon as discharge damper closes, "Blade pitch minimum" permissive comes on.

-

Associated saffron lamp on.

- Fan takes starting current (300A approx and comes down to no load current of 15A).

Red lamp ON indication comes

- Discharge damper starts opening (for the fan started).

Refer to the dampers logics.

- FD fan discharge pressure increases.

-

UCB indication

- Blade pitch for the other fan goes to minimum.

-

Associated saffron lamps come on.

- Discharge damper for the other fan closes

-

Interlock.

- Control/lub oil pressure: OK - Bearing temp is NOT HIGH. - Blade pitch is MINIMUM. - Discharge damper is CLOSED. - Control oil temp is NORMAL. - Local operator is INFORMED. 2

START the FD fan motor.

KORBA SIMULATOR

85

3

Instruct local operator to check bearing vibration and temperature.

- Bearing temperature and vibration limits are:

Fan

Vibration. Motor wdg temp.

4

ADJUST the blade pitch controller to get desired airflow.

Alarm

90 oC 80 oC

Motor

-

Trip

105 oC 95 oC

UCB indication UCB indication

2 mm/sec mm/sec. 2.5 120 oC

135 oC

- Fan discharge pressure increases.

UCB OMNIGUARD indicators must be regularly checked for bearing temperatures.

UCB indication DAS indication

-

Maintain furnace draught between-5 to 10 mm wcl and airflow 30%-40% during purging.

- Fan amperage changes accordingly. - Oxygen percentage varies accordingly. - Wind box pressure also varies, with FD fan loading 5

MAINTAIN the Wind box to furnace DP as per boiler loading.



UCB indication.

WHEN ONE FAN IS RUNNING

1

- Wind box to furnace DP should be maintained as shown: Boiler load<30%-30 to 40 mm of wcl Boiler load>30% - 100 mm of wcl

ACTION

CHECK all fan start permissive in the UCB.

OBSERVATION

REMARKS

- Bearing temperature is NOT HIGH. (<60 oC)

-

Associated saffron lamps on

- Control/lub oil pressure is OK.

-

Local check & operation

- Blade pitch controller position is at MINIMUM.

-

Local/UCB check.

- Discharge damper CLOSED.

-

Interlock.

- Both ID fans are in SERVICE.

-

UCB check only.

KORBA SIMULATOR

86

- Control oil temperature is NORMAL

-

Local check.

- The fan breaker gets closed.

-

Red lamp ON.

- Discharge damper of the fan starts opening

-

UCB indication

- Furnace pressure and total airflow increases slightly.

-

UCB indication.

- Fan discharge pressure increases

-

UCB indication.

- Fan amperage increases accordingly

-

Maintain furnace draft & Wind box DP

-

UCB vibration & bearing temperature indicators must be monitored regularly.

- Local operator duly informed. 2

3

START the FD fan

ADJUST the blade pitch to maintain desired airflow and wind box pressure.

- Furnace pressure increases slightly 4

CHECK vibration and bearing temperatures in the UCB.

- The limiting values of vibration & bearing temperatures are:

Alarm

Vibration.

2mm/ sec.pk

Trip 3mm/ sec.pk

Fan brg.

90oC

105oC

Motor Brg.

80oC

95oC

-

Check locally also.

5

ADJUST biasing set pt. to 50%.

- Biasing setpoint comes to 50%.

-

It ensures equal fan loadings on auto mode.

6

TRANSFER FD fans blade pitch control to AUTO.

- FD fan blades modulate to maintain set oxygen percentage.

-

Oxygen set point is generated as per boiler load. (Boiler master output)

- Oxygen in flue gas varies accordingly

-

Maintain 3% to 6% oxygen before APHs depending on boiler load.

KORBA SIMULATOR

87

FURNACE PURGE PROCEDURE CTION 1.

2.

CHECK ALL THE PURGE PERMISSIVE IS satisfied on the FSSS console.

ADJUST aux. air and oil air dampers' controllers to 50% position & TRANSFER damper controls to auto

KORBA SIMULATOR

OBSERVATION

REMARKS

- "No boiler trip" command is AVAILABLE.

-

- All ignitor valves are CLOSED.

-

Associated lamps corresponding to each permissive comes on in the FSSS console. UCB indication.

- All HFO nozzle valves are CLOSED.

-

UCB indication.

- HFO and ignitor trip valves are CLOSED.

-

UCB check only.

- All pulverisers and associated raw coal feeders are OFF.

-

UCB indication.

- All mill hot air gates are CLOSED

-

UCB operation from mill console

- Both PA fans are OFF

-

UCB check only.

- All fire ball and oil discriminating flame scanners must be sensing NO FLAME.

-

UCB check only.

- AC/DC electrical power supplies to FSSS panels are AVAILABLE.

-

UCB alarms indications are reset

- All auxiliary air dampers of the wind box are MODULATING& furnace to wind box DP > 40 mm wcl.

-

Permissive. UCB check

- Damper controllers come to 50%

-

UCB operation.

- After damper reset programme is over, wind box dampers modulate to maintain set WB/F DP if put on auto.

-

Refer to the note in the end of the section.

88

3.

ADJUST ID and FD fan vanes and wind box dampers to get desired airflow and wind box pressure.

- Oil elevation dampers also modulate with aux. air dampers when no oil gun is in service

-

Refer to the secondary air damper control logics

- Boiler airflow less than 30% annunciation goes off.

-

On the total airflow indicator 27% and 36% airflow corresponds to 30% and 40% boiler MCR airflow values.

- All burners at all elevations and in all corners, come to horizontal position

-

UCB indication.

- "Burner tilts horizontal and Airflow less than 40%" permissive comes ON.

-

UCB indication.

- If all other permissive are satisfied, "Purge Ready" indication comes ON.

-

UCB check only.

- "Purging" indication comes on the FSSS console.

-

UCB indication.

- If in the meanwhile none of the permissive are lost, "Purge complete" indication comes on FSSS console, with a time delay of 5 minutes.

-

Refer to the FSSS logics

- MFR-A & MFR-B get reset.

-

Indication on FSSS

-

UCB annunciation.

- Boiler airflow and wind box pressure are maintained at less than 40% and 40 mm wcl, respectively. 4.

5.

ADJUST burner tilt controller to 50% position

PRESS "push to purge" button on the FSSS console

- Boiler Trip "cause" also resets. - "Boiler MFR Trip" annunciation clears off.

KORBA SIMULATOR

89

WIND BOX CORNER NOZZLE ASSEMBLY

As soon as "NO BOILER TRIP" permissive becomes available, a "post trip damper reset programme" is initiated. A separate timer starts and after a time delay of 5 minutes, coal air dampers are closed in a phased sequence, from the top. Elevation, F, E and D closes first; then with a time delay of 5-second, elevation C, B and A close. After all the coal air dampers are closed, 10 sec later, all auxiliary air and oil air dampers are released for modulation. If the air damper controllers are in manual, auxiliary dampers and oil dampers together follow auxiliary air damper controller output. If the controllers are in auto, they will modulate together to maintain set wind box to furnace DP. When oil is introduced, oil air dampers modulate as a function of oil header pressure. After feeders are started, corresponding coal air dampers modulate as a function of feeder speed, if put on auto. Wind box to furnace DP must be maintained 40 mm wcl, when boiler loading is less than 30% MCR. Above 30% loading wind box to furnace DP must be constantly ramped up to the maximum of 100 to 120 mm wcl, at full load.

KORBA SIMULATOR

90

BOILER LIGHT-UP PREPARATION FOR BOILER LIGHT-UP

1.

ACTION

INSTRUCT fuel station operator to start HFO & light oil (HSD), pumps.

- HFO supply header pressure starts increasing, up to 24

OPEN HFO short Re-circulation valves, HO-55.

4

INSTRUCT local operator to

-

-

-

-

Put all HFO guns in their guides.

Minimum 17 2

Ignitor oil pressure (HSD) comes up, at the unit fuel station locally. -

UCB indication.

HFO temperature starts increasing, provided HFO re-circulation is charged.

-

Associated steam line drains must be opened. Local.

-

HO-55 valve open indication comes on & oil flow is established up to the HFO trip valve.

-

UCB indication. Not required if other units are on oil firing.

-

Oil gun ADV/RETRACT indication comes in the UCB.

-

Local operation

Corresponding indication comes on, in the UCB.

-

Local operation

Check guns ADVANCE/ RETRACT mechanism.

Atomising steam pressure starts increasing up to

REMARKS

kg/cm supply header Pressure is required for opening HOTV.

2

INSTRUCT firing floor operator to charge HFO heating and Atomising steam lines locally -

3.

-

Kg/cm . -

2.

OBSERVATION

2

8.5 Kg/cm .

'Put guns' selector switches on REMOTE.

-

Associated gun on REMOTE indication comes in the UCB.

-

Permissive. Local Operation

Open all isolating valves on oil & steam lines of all HFO guns

-

No indication in the UCB.

-

Gun start permissive. Not simulated.

KORBA SIMULATOR

91

BOILER LIGHT-UP PROCEDURE

1.

ACTION

CHECK these conditions before the boiler light up

OBSERVATION

REMARKS

-

Boiler "MFR TRIP" is RESET.

-

Purging complete. UCB indication.

-

Pre-start checks for boiler light up have been COMPLETED.

-

Local/UCB check.

-

Fuel oil system is adequately LINED-UP.

-

Local operators responsibility.

-

Local operation.

-

Super heater / Reheater air vents are OPEN.

-

SH/RH start-up vents are OPEN.

-

UCB operation

-

Ignition air fans are LINEDUP for operation

-

Local operation

2.

Open heavy fuel oil recirculation valve

-

HFO re-circulation valve opens up.

-

UCB indication Interlock before opening HFO trip valve.

3.

OPEN heavy fuel oil trip valve

-

HFO trip valve opens up.

-

-

Short re-circulation valve closes.

-

UCB indication on FSSS console. Interlock. UCB indication.

-

HFO header pressure rises up

-

UCB indication.

-

UCB annunciation.

4.

5.

OPEN heavy fuel oil control valve.

OPEN Ignitor oil trip valve

KORBA SIMULATOR

2

to 10 Kg/cm (approx.) -

"HFO" inlet and re-circulation flow start increasing

-

"HFO header pressure very low" alarms clear off.

-

HFO temperature in the HFO header increases up to 110 oC

-

UCB indication.

-

Ignitor oil trip valve opens up.

-

Associated red lamp comes on.

-

Ignitor air fans A & B, start

-

Refer to ignitor 92

automatically.

6.

CHECK these parameters are within their operation limits.

trip valve logics.

-

Ignitor oil and ignitor air pressure increase up to 23 2 Kg/cm and 400 mm wcl, respectively.

-

UCB indication.

-

"Ignitor air to furnace DP low" & "Ignitor oil/Atomising air pressure low" & "Ignitor oil/HFO trip valve closed" alarms clear off.

-

UCB annunciations /Indication.

-

Drum level normal (-60 mm. to 0, preferably on lower side).

-

To take care of swelling effect

-

HFO temp. 110 oC . (Min. temp. required is 95 oC).

-

HFO trip valve closes at 93 oC.

HFO atomising steam 2 pressure 8.75 Kg/cm

HFO trip valve is tripped at 2 6.5 Kg/cm atomising steam pr.

Light oil pressure more than 2

15 Kg/cm . Ignitor atomising air pressure 2 5 to 7 Kg/cm

Ignitor trip valve closes at 8 2

Kg/cm of light oil pressure and 2 4.5 Kg/cm of instrument air pressure. Wind box pressure between 35 to 40 mm wcl

7.

ADJUST HFO header pressure set point to 2 50%(13 Kg/cm ) and TRANSFER its control to auto.

KORBA SIMULATOR

-

HFO header pressure set point is provided above the HFO pressure controller.

-

HFO pressure controller transfers to auto and modulates to maintain the set HFO header pressure.

-

M/A release must be pressed for auto / manual changeover.

93

8.

CLOSE heavy fuel oil re-circulation valve.

-

HFO re-circulation flow valve closes. HFO re-circulation flow comes to minimum position

-

UCB indication.

-

UCB check only.

-

HFO header pressure goes up and is brought down to set HFO pressure by auto controller

-

Controller action.

-

In the first 10 secs of the pair start trial time; ignitors 1-3 and 2-4 are proven, in the associated oil elevation.

Associated ignitors “ON” indications come on.

-

"Ignitor Stop" light goes off in the associated elevation.

-

If the flame is not proven, spark ceases and ignitor Jamesbury valve closes.

If minimum 3 ignitors are proven on, command goes to corner 1 or 2, for the gun to advance to the firing position, provided associated ignitor is on

-

Minimum three ignitors should be proven ON.

-

9.

PUSH " Pair 1-3 or 2-4 Start" push button.

KORBA SIMULATOR

-

Gun. "Advance", lamps come on

-

Command is given to open the associated atomising steam valve after the gun is fully advanced.

-

Refer to the FSSS logics.

-

After the atomising steam valve is fully open, command is given to open the corresponding HFO corner nozzle valve.

-

Refer to the FSSS logics

-

25 second later command goes to corner 3 or 4, as the case may be, HFO nozzle valve to open.

-

UCB indication

-

Associated discriminating discriminating oil flame scanners start sensing flame.

-

Refer to the FSSS logics.

94

10.

ADJUST heavy oil pressure controller to desired firing

-

HFO control valve modulates to maintain set HFO header pressure

-

Maximum HFO header pressure must not be more than 13 Kg/cm2 (alarm)

-

HFO header pressure changes accordingly

-

HFO trip valve trips at the header pressure of 3.5 Kg/cm 2

-

Oil scanner performance improves with increasing header pressure.

11.

PUSH second pair "Start"(Pair 1-3/2-4) push button.

-

HFO guns advance and corresponding nozzle valves open up.

-

Refer to the FSSS oil gun logics.

12.

PUSH "Ignitor Stop" push button to remove ignitors if the oil flame is stable in every corner in the elevation

All the elevation ignitors go off.

-

UCB indication.

-

KORBA SIMULATOR

If any discriminating scanner flickers to show 'no flame', corresponding oil nozzle valve is closed automatically

95

PA FAN OPERATION PRE-START CHECKS 1

2

3

ACTION

CHECK that all PA fans start permissive is satisfied.

CHECK that PA fan is locally line up for starting.

CHECK. if air system is lined up before starting PA fan.

KORBA SIMULATOR

OBSERVATION

REMARKS

-

PA fan bearing temp NOT HIGH (<60oC.).

-

Local/UCB checks.

-

PA lub oil pressure is ADEQUATE.

-

If not, instruct local operator to line-up.

-

PA fan inlet guide vanes are at MINIMUM position.

-

This permissive is satisfied after the first PA fan start command is given.

-

PA fan FSSS start command is AVAILABLE (BOILER MFR: RESET & all mill cold air dampers are less than 5% OPEN).

-

This permissive is satisfied after the first fan start command is given.

-

PA fan discharge damper is CLOSED.

-

Interlock.

-

PA fan lub oil coolers are CHARGED from aterside.

-


-

PA Fan LOP : ON and other pump is on AUTO

-

Local operation and check.

-

PA fan lub oil tank level is ADEQUATE.

-

Local check.

-

PA fans EPBS are in RELEASED position.

-


-

PA fan guide vanes are on REMOTE. Instrument air pre. is AVAILABLE.

-

Local operation/ check.

-

PA fan discharge damper is OPERATIONAL and power supply is AVAILABLE. APHs primary air isolation dampers are OPEN.

-

Local check.

-

UCB indication.

-

96

-

Seal air fans are LINEDUP and their suction dampers AD-31/32/33 are OPEN.

-


-

Mills' cold air dampers on REMOTE. Instrument air pre. is AVAILABLE.

-


-

Furnace purging is COMPLETED and MFRs are in RESET condition.

-

FSSS start command requirement is met.

-

All man material is removed from the pulverisers.

-

Local check.

STARTING PROCEDURE WHEN BOTH THE FANS ARE OFF

ACTION

1 CHECK these conditions before starting the PA fan.

KORBA SIMULATOR

REMARKS

-

All pre-start checks COMPLETED.

-

Local/UCB check.

-

Fan discharge dampers 100% OPEN.

-

UCB check only.

-

Regulating Regulati ng vanes are 100% OPEN.

-

UCB indication

-

If not, ask the local operator to line-up. This permissive becomes available once the first PA fan start command is given.

-

2 START the PA fan motor.

OBSERVATION

Lub. oil pressure is ADEQUATE. (>.1.8 Kg)

-

FSSS start command (MFR - A&B reset on the FSSS console and all mills cold air dampers are less than 5% open) is ON.

-

-

Bearing temperature temperature NOT HIGH. (<60 O C).

-

Saffron lamp on. (Permissive)

-

Discharge damper starts closing.

-

-

Regulating vanes of the fan get closed.

-

Associated red and green lamps come on. Saffron lamps (permissive) (permissive) glow on. 97

3 ADJUST the PA fan guide vanes to get desired hot PA header pressure of 760 mm wcl

4 INSTRUCT the local operator to check bearing Temperature Temperature & vibration locally.

-

All mills cold air dampers go to less than 5% open and "FSSS start command" permissive comes on.

-

Saffron lamp (permissive) (permissive) glow on.

-

CB closed indication indicati on comes on.

-


-

Fan current shoots up to 700A and comes to No load current 70A.

-

UCB PA Fan ammeter.

-

Discharge damper opens and for the other fan, it closes and regulating vanes of the other fan also goes to minimum position

-

UCB indication.

-

PA fan discharge pressure goes up.

-

Maintain furnace draught (-5 to -10 mm.)

-

PA fan current go up.

-

Maintain desired airflow in furnace. f urnace.

-

PA header pressure goes up to 760 mm wcl, gradually.

-

Limiting values of bearing temperature and vibrations

-

UCB OMNIGUARD & vibration indicators must be regularly monitored when the fan is running.

Alarm

Trip

Fan

96oC

105oC

Motor

85oC

95oC

Vibration Vibrat ion

2 mm/ sec.

Motor winding temp. -

KORBA SIMULATOR

110oC

3 mm / sec.

130oC

There must be no abnormal sound from the fan or bearings.

- DAS points -

Local check

98

WHEN ONE FAN IS RUNNING 1

ACTION

CHECK before starting the PA fan.

OBSERVATION

REMARKS

- All pre-start checks are COMPLETED.

-

Local/UCB check.

- LOP: ON. Lub. oil pressure ADEQUATE (1.8 -2.5 KSC)

-

Corresponding saffron lamp (permissive) on.

- Discharge Discharg e damper (AD-15/16: CLOSED.

-

UCB check.

- Regulating vanes are in MINIMUM position.

-

Associated controller output is 0%.

- Bearing temperature temperature NOT HIGH (< 60 O C )

-

Associated saffron lamp is on.

- FSSS start command is AVAILABLE.

-

Permissive.

- Breaker closed indication on. - Fan current goes up to 700A and comes down to no load current of 70A. Discharge damper AD-15/16 open up.

-

Red lamp is on.

- Limiting value of bearing vibration and temperatures are:

-

- Local operator informed prior to starting of the fan. 2

3

START the PA fan motor.

INSTRUCT the local operator to check bearing vibration and temperature locally.

Alarm

Fan.

95oC

105oC

Motor

85oC

95oC

Vibration. Vibrat ion.

2 mm / sec. pk.

Vibration and the OMNIGUARD bearing temperature indicators in UCB must be monitored regularly. Trip

3 mm / sec. pk.

- There should be no abnormal sound from the fan/bearings, locally

KORBA SIMULATOR

-

-

Local checks.

99

4

ADJUST the fan guide - Fan discharge vanes to get desired PA pressure read approx. header pressure and 800 mm wcl. equalise fan loadings. - PA header pressure rises to 760 mm wcl.

-

Maintain PA Header pressure 760 mm wcl constantly

ADJUST the fan biasing and header pre. set point to 50% & 80% respectively and transfer vane controllers to auto.

- Header pressure and biasing set points have been provided over the IGV controllers of PA fan A&B respectively.

-

Biasing set point can be altered suitably to change the fan loadings.

- IGVs of both fans modulate to maintain set header pressure.

-

Normal biasing is 50% for ensuring equal fan loadings.

SHUT DOWN PROCEDURE WITH BOTH THE FANS RUNNING

ACTION

OBSERVATION

1

TRANSFER the IGV controls to manual

2

STOP all the pulverisers in excess of three from the top.

3

4

REDUCE IGVs of the fan to their minimum position.

STOP the fan motor.

KORBA SIMULATOR

-

REMARKS

Manual mode indication comes on.

-

Use the M/A release

Three pulverisers only can be in service with one PA fan.

-

If needed, stop more pulverisers, to maintain the PA header pressure at 760 mm wcl

Cut-in oil support if odd combination of mills are running.

-

-

Fan discharge pressure comes down.

-

UCB indication.

-

Notice the other fan loading going up, to maintain the set header pressure.

-

If needed keep the second fan also on manual & maintain PA header pressure.

-

The fan breaker opens Discharge damper (AD-15/AD-16), starts closing.

-

UCB indication. Associated green lamps come on.

-

Regulating vanes go to minimum, position

-

UCB/local check.

100

WITH ONE FAN RUNNING 1

ACTION

SHUTDOWN all running pulverisers one by one.

OBSERVATION

REMARKS

- Boiler total fuel flow starts decreasing.

-

Adequate oil elevation must be cut-in before stopping pulverisers.

- Oxygen percentage in the flue gases starts increasing.

-

Ensure adequate FD fan loading & wind box dampers opening to prevent airflow from going < 30% tripping the boiler inadvertently.

- PA fan discharge pressure starts decreasing.

-

UCB check only.

- PA header pressure decreases to 400 mm wcl, approximately.

-

Maintain airflow and furnace draught

STOP the PA fan & - Breaker open Rack-out the breaker indication comes on. if required for maintenance. - Guide vanes of both PA fans will remain at minimum position.

-

UCB indication.

-


- Associated mills cold air dampers start closing. - Total airflow keeps on decreasing. - ID fan vanes modulate (on auto), to maintain set furnace draught. 2

3

REDUCE the IGV of the PA fan to its minimum position.

- Discharge dampers of both PA fans go to 100% open.

KORBA SIMULATOR

101

PULVERISER OPERATION PRE-START CHECKS 1

ACTION

CHECK that all the pulveriser start permissive is satisfied.

OBSERVATION

REMARKS

- Pulveriser START PERMIT is AVAILABLE. (Boiler total airflow is < 40% and all burners are HORIZONTAL).

-

Alternatively, if anyone coal feeder is proven then start permit will come from the proven feeder.

- Mill discharge valves at all four corners are OPEN. - Local feeder selector switch is ON REMOTE.

-

UCB operation.

-

Local operation/check. Not simulated.

- Mill tramp iron gate is 100% OPEN.

-


- Cold air gate of the mill is 100% OPEN.

-


- Pulveriser seal air valve is 100% open.

-

Local operation Not simulated. Seal air valve opens on interlock when pulveriser is started.

- "No unsuccessful start" permissive for pulveriser is ON.

-

Refer to FSSS logics. UCB check only

- "No pulveriser trip" command is present.

-

UCB check. Refer to FSSS permissive

- Pulveriser PA Fan permit is AVAILABLE.

-

Anyone or both PA fan on and PA header pressure 700 mm WCL

- Mill ignition energy permit conditions are SATISFIED. (Minimum 3 out of 4 gun nozzle valves in adjacent elevation are open and elevation oil flow is more than 30% OR adjacent feeder speed is more than 50% and boiler load is more than 30%.

Interlock. Refer to FSSS logics for more details on ignition energy condition requirements.

KORBA SIMULATOR

102

2

CHECK if the - All man and material pulveriser is locally removed from site. lined up for operation.

-

Local check.

- Pulveriser oil bath level is ADEQUATE

-

Local check.

- Cooling water isolation valves to oil bath coolers are OPEN.

-


- Mill cold air and hot air dampers are OPERATIONAL and on REMOTE. Instrument air pressure is available

-

Local check and operation. Not simulated.

- Seal air to pulveriser differential pressure is 125 mm wcl.

-

UCB alarm and indication.

- Raw coalbunker level is ADEQUATE and bunker gate is OPEN.

-

Local check/operation. check/operat ion.

MILL STARTING PROCEDURE

ACTION

1 CHECK these before starting any mill.

-

OBSERVATION -

UCB/Local check.

-

Local check lamps are on

Electrical supply is AVAILABLE. Breaker is RACKED IN/REMOTE position and feeder selection switch is in remote position. - Mill's cold and hot air dampers (CAD/HAD) CLOSED.

-

Local check. (Not simulated).

-

CADs are <5% open.

-

-

Anyone PA fan 'ON' & PA Hdr pr. 770 mm wcl.

-


REMARKS

All per missives are AVAILABLE.

-

KORBA SIMULATOR

P.A. permit is AVAILABLE.

103

2 START the pulveriser.

3 OPEN the CAD/HAD to maintain desired airflow and mill outlet temperature.

4 CHECK before starting the mill feeder.

-

Pulveriser Pulverise r on MANUAL MODE.

-

-

Pulveriser start red lamp comes on.

-

-

Pulveriser starting current settles down at 12 amps.

-

Mill cold air damper opens 100%.

-

Mill airflow 80 T/Hr. (app.).

-

Mill differential pressure goes up to 100 mm wcl approximately.

-

PA header pressure dips slightly until auto controller opens the PA fan guide vanes.

-

Hot air gate open temperature increases i ncreases..

-

UCB check.

-

Mill differential pressure goes up to 100 mm wcl, approximately.

-

Maintain mill outlet temp at 75 O C & mill airflow at 60 T/Hr

-

Coal silo gate is OPEN.

-

If not, get it opened.

-

Feeder speed is MINIMUM (0% - 20%), corresponding to 9 T/Hr.

-

Feeder start permissive.

KORBA SIMULATOR

If not, set on manual.

It's a good practise to keep primary header pressure control on AUTO, so that at the time of sudden opening of CAD, pulveriser does not trip(time delay 5 sec.) due to dip in the PA header pressure(585 mm.).

104

5 START the mill feeder.

6 RAISE mill feeder speed gradually.

7 ADJUST flow & temp control set points to 70% and 50% respectively and RELEASE mill air control to auto.

-

The entire mill permissive is AVAILABLE.

-

''Pulveriser Ready'' lamp indication is on.

-

Mill outlet temperature > 55 O C.

-

Feeder start permissive.

-

Mill ignition permit is AVAILABLE.

-

UCB Check.

-

Feeder ON indication comes on.

-

Maintain mill temp and airflow, as recommended.

-

Coal flow indicator reads 9 T/Hr. approx.

-

Maintain furnace draught.

-

Mill current starts increasing.

-

UCB check only.

-

Mill outlet temperature tends to come down.

-

Control coal-firing rate to control mill outlet temperature.

-

Mill differential pressure goes up to 180 mm wcl. at 34 T/Hr. coal firing, depending upon coal quality & mill condition.).

-

Mill current goes up to 30 -32 amp. At maximum loading of 34 T/Hr. depending upon the coal grindability (Hargrove index).

-

Mill outlet temperature may tend to drop.

-

Flow & temp Control set points are provided over CAD & HAD respectively.

KORBA SIMULATOR

-

Watch the flame quality improving in coal flame scanners. If flame is not good, instruct the local operator to check the furnace flame and oil flame. If the need be increased the HFO pressure by adjusting HFO control valve (to 2 approx. 12 Kg/cm .) to improve flame quality.

Refer to ACS drawings for details of flow and temperature controllers of the pulveriser.

105

8 CHECK the mill locally for any abnormal sounds, reject rate and return oil flow.

-

CAD & HAD modulates to maintain 60 T/Hr.of airflow and 75 O C of mill outlet temperature. temperature.

-

There should be no abnormal hunting of mill current, which is indicative of foreign material ingress, usually.

-

Local check only.

Return oil continuous flow should be noticed through local Sight glass.

-

Whenever the mill amp or DP is rising mill rejects must be evacuated.

NOTE: -

Oil support can be withdrawn or reduced depending upon LOAD, IGNITION ENERGY and FEEDER F EEDER PROVEN criteria.

-

Operator must monitor continuously continuously the mill temperature and bowl DP, which should not exceed 95 oC and 200 mm wcl respectively.

-

Before starting mill, operator must make sure water supply for oil bath coolers.

-

Mill outlet temperature should be in between 80 oC to 85 oC during start-up. In no case it should be less than 60 oC and more than 90 oC.

-

Coal feeding should be reduced if desired mill temp. is not maintained. maintained. (When hot air damper is 100% open).

KORBA SIMULATOR

106

MILL SHUTDOWN PROCEDURE

ACTION

OBSERVATION

1 TRANSFER mill feeder and fuel master controller to manual.

- Fuel master and feeder control transfer to manual.

-

2 REDUCE feeder speed to minimum, gradually.

- Coal flow to mill starts coming down.

-

3 STOP the mill feeder.

REMARKS M/A release push button must be pressed for auto/manual changeover. Maintain `mill temperature and airflow.

- Other running feeders start loading up, to maintain boiler loading, if on auto.

Maintain loading on the running mills by adjusting the fuel master.

- Feeder Off' indication comes on, in the mill console.

-


- Hot air gate closes with a time delay of 30 sec approx.

-

UCB indication.

- Mill current and differential pressure start reducing as the mill becomes empty, gradually.

-

UCB indication.

-

UCB check. Local operation.

-


4 EVACUATE the - Mill temperature comes mill reject chamber down to less than 50 oC. locally and STOP the mill. - Mill CAD goes to <5% open - Airflow to furnace drops slightly.

KORBA SIMULATOR

107

TURBINE AND GENERATOR SYSTEM OPERATION

KORBA SIMULATOR

108

KORBA SIMULATOR

109

VACUUM PULLING

1

ACTION

CHECK before starting vacuum pulling operation.

-

-

OBSERVATION

Auxiliary steam header charged and its pressure ADEQUATE. Ejector PRDS is CHARGED and Ejector steam pressure is 2

ADEQUATE ( 7.5 Kg/cm )

REMARKS

- Aux. steam pr. must 2

be 14 Kg/cm

- “Ejector steam pr. low" alarm should not be there.

-

At least one condensate pump is ON.

- UCB operation

-

Main ejectors and GSC CHARGED from the waterside (MC-11, 12, 13, 14, 19, 20 OPEN & MC-15, 21 CLOSED).

- Local operation DAS check points Refer to condensate system.

-

Condenser air valve CA-1/CA2 & air valves to main ejectors, CA-3/CA-4, are OPEN.

- Local operation. Not simulated

KORBA SIMULATOR

110

-

Surge tank level ADEQUATE.

- UCB operation.

Condenser siphon filling COMPLETED.

- Local operation. Not simulated.

-

Condenser vacuum breaker - UCB Local valve must be CLOSED. Water operation. sealing done.

-

Condenser inlet & outlet valves are CLOSED.

-

Steam line drains to flash tank, are CLOSED

- UCB operation & check.

-

MOT level is NORMAL and "MOT level low" alarm is RESET.

- UCB check and SGC 'Operation Release' condition.

-

At least one MOT vapour extractor fan is ON.

- SGC operation release criteria. UCB operation and check.

-

Generator hydrogen pressure

- UCB/SGC check.

- UCB operation. DAS indication

2

must be 3.5 Kg/cm . -

Generator hydrogen purity > 97%.

- UCB indication. SGC criteria.

-

Hydrogen seal oil pressure should be more than 4.8

- UCB indication & SGC criteria.

2

Kg/cm . -

Seal oil to hydrogen DP is 2

ADEQUATE, 1.2-1.5 kg/cm . 2

START AOP and one JOP.

- UCB indication & SGC criteria.

-

"Control oil pressure low" and "Lub. Oil pressure low" alarms get cleared off.

- UCB indication & check only.

-

Control oil pressure increases

- UCB indication.

2

-

3

SWITCH-ON SLCs of AOPs, JOPs, EOP, Gate valve

-

KORBA SIMULATOR

to 6.8 Kg/cm . Jack oil pressure increases up 2 to 130 Kg/cm . "Jacking oil pressure low" alarm clears off. Corresponding SLCs come on.

- UCB indication.

These operations up to Step-3 can be executed 111

gearing and the Lub. Oil temp controller.

4

5

CHARGE condenser priming ejector from steam & airside.

INSTRUCT local operator to start one CW pump and CHARGE both condensers 50 % approx., to curb CW power consumption.

automatically by SGC OIL Start-up programme. -

Turbine starts barring at 110 rpm approximately.

-

Lub oil temperature controller modulates to maintain set lub oil temperature.

-

AS-83, CA-15 & CA-16 are opened.

-

Condenser water box priming initiated.

-

CW header pressure increases, slightly.

-

Condenser inlet & outlet valves are partially opened.

-

- Local operator DAS check.

- DAS indication.

- UCB operation.

-

Condenser flow starts increasing.

- DAS indication.

6

CUTOUT the priming ejector after CW water starts coming from the air vents of priming ejector.

-

Priming ejector's steam and airside valves are closed.

- Local operation.

7

OPEN seal steam line and header drains & CHARGE gland sealing steam into the turbine glands.

-

AS-85 and SLC gland steam drains are opened.

- UCB operation.

-

Gland seal steam control opens up and gland steam header pressure starts increasing.

- UCB operation.

TRANSFER seal KORBA SIMULATOR

-

Seal steam pressure control

- Maintain a pressure 112

steam control to auto. 8

9

CHARGE starting ejector by opening ejector’s steam supply & air suction valve.

transfers to auto mode.

-

Starting ejector steam supply valve AS-80/ AS-81 is opened.

-

Air suction valve to starting ejector (CA-5/CA-6) is opened.

-

Condenser vacuum starts 2 increasing to 0.7 Kg/cm .

OPEN steam supply valve to any one main ejector as per desired vacuum. -

10 ISOLATE starting ejector by closing air suction valve first and then steam supply valve.

2

of 0.01 Kg/cm in the seal steam header. - UCB operation.

- UCB operation after steam supply valve is 100% open - UCB indication.

Vacuum builds up to 0.92 2 Kg/cm i.e 72 mm Hg (approx)

- UCB indication.

Turbine barring speed increases up to 220-RPM approx.

- UCB check only.

-

"Condenser vacuum low" alarm gets cleared off.

- UCB annunciation.

-

Air suction valve (CA-5/CA-6), gets closed first.

- UCB indication. Interlock.

-

Ejector steam supply valve (AS-0/As-81) is closed.

- UCB operation.

Condenser vacuum is

-

11 MAINTAIN rated condenser vacuum of 73 mm Hg (back pressure)

KORBA SIMULATOR

2

maintained at 0.92 Kg/cm .

Condenser backpressure high alarm is at 150 mm Hg and turbine tripping at 225 mm Hg.

113

HP BYPASS AND LP BYPASS CHARGING 1

ACTION

CHECK before charging HP/LP bypass system.

OBSERVATION

REMARKS

-

Boiler stop valves S-42 & S-64 are OPEN

-

UCB operation.

-

M S pressure 12 Kg/cm .

2

-

UCB check.

-

CRH and HRH steam line drains are OPEN.

-

UCB operation.

-

HP bypass oil unit's oil level NORMAL, its Pump ON and its pressure ADEQUATE.

-

Local check.

-

LP bypass rack is LINED UP and all setting & tripping values checked.

-

Local operation

-

HP bypass downstream temperature set point is at 200 O C approx.

-

Can be altered to maintain desired HRH steam temp.

-

HP bypass spray pressure set point: 70 2 Kg/cm .

-

UCB operation.

-

All isolating valves before the spray pressure controller are OPEN.

-

Local operation/ check. N simulated.

-

HP bypass upstream pressure (main steam pressure) set point is at

-

Can be altered later to maintain desired main steam pressure.

UCB indication.

2

10 Kg/cm . 2

TRANSFER LP bypass control to auto and SWITCHON the Automatic Control Interface (ACI).

-

LP bypass control transfers to auto.

-

-

HRH fixed set point 2 comes to 3 Kg/cm .

-

KORBA SIMULATOR

Refer to the text on LP bypass. (Volume-1)

114

3

4

TRANSFER HP BP control to auto.

ADJUST main steam pressure set point to obtain desired MS pressure.

-

HP bypass control transfers to auto.

-

-

HP bypass valves (BP1/BP-2) start opening if MS pr. is more than the set point.

-

-

CRH pressure starts increasing.

-

UCB indication.

-

HP bypass temp controller and spray pressure controller transfer to auto and maintain set values of downstream temp & spray pressure.

-

Interlock.

-

Main steam pressure is maintained as per the set point.

-

HP bypass valves open or close, depending on whether set point is less or more than the MS pressure respectively.

-

UCB operation.

UCB alarm "HP bypass valves open" comes on.

HP bypass console indication.

Biasing should be maintained positive (set point less than MS Pr.) to ensure that HP bypass remains open to maintain sufficient steam flow in R/H

NOTE: 1.

MS pressure set point must not fall too much below the actual MS pressure; otherwise due to pressure interlock (error deviation + 10), a fast opening command is given to HP bypass control valves.

2.

At 380 O C, HP bypass valves receive a closing command and their control trips to manual. The temperature set point must be suitably altered to maintain the desired HRH temperature.

3.

For details on ACI (Automatic Control Interface) device, please refer to the text on HP/LP bypass system (Volume-1)

KORBA SIMULATOR

115

TURBINE START- UP PRE-START CHECKS 1

2

ACTION

CHECK that all the turbo-Supervisory instrumentations are functional.

CHECKS before starting the turbine run-up

All UCB indicators and recorders are functional and healthy.

-

All recorders are inked and all instruments are calibrated.

-

Electro-hydraulic controller for turbine is ON.

Electrical supply for the EHC must be ON (C&I).

-

EHC isolating valves on sec oil lines to control valves are open.

-

Local operation

-

Electro-hydraulic controller's output is zero.

-

Indication on governor console.

-

"EHC control fault" and "EHC Plunger coil off" alarms do not appear in the UCB.

-

UCB annunciation. If alarms are on, inform C&I maintenance

-

If not, bring it down to zero. The indication is on turbine governor console.

-

Load reference set point for the Load Controller and the load limiter output are zero.

If not, bring it down to zero.

-

Speeder gear position is 100%.

-

If not, raise the speeder gear position to 100%.

-

Starting device is at 0% position.

-

UCB operation. UCB indication.

Speed reference set point for the Speed Controller is zero or less than the barring speed.

-

REMARKS

-

-

KORBA SIMULATOR

OBSERVATION

If required, contact the related C&I engineer for maintenance.

116

-

The alarms "TSE influence off" "Turbine stress effects off" and "Turbine stress cubicle fault" are not on. TSE influence is ON.

-

TSE influence can be made on from turbine relay panels. Local operation.

-

Unit trip relay (A & B) are in RESET condition

-

If not, reset UTRs after resetting MFR. GTRs and checking if stator water flow & conductivity are normal (UTR reset permissive)

-

UCB check only

Alarm

-

"Turbine Trip" and "Turbine Trip gear operated" alarms are not on and Trip oil 2 pressure > 5 Kg/cm All differential expansions of the turbine are NORMAL and within the alarms values HPT IPT LPT

-

Condenser vacuum is NORMAL. 0.92 Kg/cm approx.

-

KORBA SIMULATOR

2

Turbine SLC Drains is ON and NOT FAULTED. "SLC Drains fault" Alarm is not ON.

Trip

+4.5mm

+5.5mm

-2.5mm

-3.5mm

+5.0mm

+6.0mm

-2.0mm

-3.0mm

+25 mm

+30 mm

- 5 mm - 7mm - "Condenser vacuum low" (150 mmHg) & "Turbine electric protection for low vacuum" (225 mm Hg) are not ON. -

These drains can be switched ON/OFF from the SLC section on turbine panel.

117

-

Turbine stop valves (ESV1&2, IV-1&2). Control valves (HPCV-1&2), IPCV1&2). Extraction block valves (ES-1,2,3,7,5,6) are CLOSED.

-

Check from both UCB indicators and local indicators.

-

Extraction NRV's (A2, A3, A4, A5) and CRH line NRV's L/R are CLOSED.

-

UCB indication.

-

The turbine is on BARRING and there is no abnormal sound from the turbine & its bearings.

-

Gate valve gearing is open.

-

The Speed of rotation of shaft is between 200 and 220 rpm.

-

UCB indication.

-

Turbine "Control oil pressure" is greater than 5 2 Kg/cm

-

Normal value is 6.5 to 6.8 Kg/cm2 with AOP and 7.5-8.5 2

-

Turbine lub oil temperature after coolers is normal i.e. 45oC. (40oC + 5O C )

-

Kg/cm with MOP. UCB indication.

-

Lub oil pr. is normal at 3.5

-

UCB check

2

Kg/cm before coolers.

3

CHECK that the entire turbine MS strainer drains CRH drains HRH strainer drains and ESV & IV before seat drains are open.

KORBA SIMULATOR

-

Main oil tank level is NORMAL.

-

Local check. Normal value is zero.

-

Thrust bearing oil filters are NOT CHOKED.

-

Local check. UCB alarm reset.

-

MS strainer drains (DW-51/52/53/54) to flash tank are OPEN.

-

Indications of all electrical drains available in UCB. In case anyone is not open (indicated by green lamp on), open the same with the respective control switch.

118

-

CRH drains (DW-160/161/162/163) to flash tank are OPEN. HRH strainer drains to flash tank, (DW125/126/131/132) are OPEN ESV & IV before seat drains to flash tank (DW-121/ 122/123/124 and DW127/128/129/130) are OPEN.

4

CHECK that the generator seal oil and stator water system are in service and healthy

-

Generator hydrogen pressure is NORMAL, more than 3 Kg/cm2

-

3.5 Kg/cm max. UCB/local indication.

-

Seal oil pressure (turbine and exciter side) is more

-

UCB check

-

UCB recorder.

-

Normal value is

than 4.8 Kg/cm -

2

2

Seal oil to hydrogen DP is 2

NORMAL (1.2 Kg/cm ) -

Stator water flow is more 3

3

than 23 m /Hr. -

Stator water specific conductivity is less than 1 micro mho/cm.

-

-

Stator water pressure is 2 NORMAL. (2.8 Kg/cm )

-

UCB / local indication

-

UCB operation.

-

UTR reset permissive

-

KORBA SIMULATOR

27 m /Hr.

Generator and field breakers are in RESET condition and Generator /Field breakers tripped" & "Generator trip relay operated" alarms are reset.

Maximum allowable value is 5 micro mho/cm.

119

TURBINE ROLLING PROCEDURE 1

ACTION

CHECK turbine startup criteria as determined from the X-curves.

OBSERVATION

REMARKS

-

Main steam, at the turbine inlet should have minimum of 50 oC superheat.

-

Applicable during all turbine start-ups.

-

M.S. pressure is 30 KSC approx. & temp. 280 oC

-

For cold start-up only.

-

Criteria for Opening the ESVs.

-

Max/Min. SH steam temp. depending upon mid wall temp. of HPCV.

-

Start-up curves 1, X-2 and X-3

-

Rolling to warm-up speed of 600 rpm.

-

Max. MS temp depending upon saturated steam temp and mid body temperature of HP casing/ shaft

-

Start-up curves X-4 and X- 5.

-

Rolling up to rated speed of 3000 rpm.

-

Required minimum mean metal temp of H.P Shaft depending upon available MS temp.

-

Start-up curve X-6

-

Loading the turbine after synchronisation.

-

Required minimum mean metal temp of IP shaft, depending upon the available HRH steam temp.

-

Start-up curve X-7

2

Maintain boiler side steam parameters as required for turbine start-up.

-

The MS/HRH temp and pressures are within the determined ranges.

-

UCB indicators are available for all these values.

-

HRH steam pressure should not be more than 2 15 Kg/cm during rolling.

-

Low HRH pr. during startup is to prevent HP exhaust temp rising too high.

-

Start-up oil pr. Falls to 1.8 KSC and HP ESVs (1&2) open 100% at 42% position of starting device.

-

UCB indication on turbine governor console.

-

Interceptor stop valves (1&2), open 100% at 56% position of starting device.

-

UCB indication on turbine governor console.

-

Start-up oil pre. = 0 at 70% of starting device position.

-

UCB indication.

3

RAISE starting device to 70% gradually.

KORBA SIMULATOR

X-

120

Aux Sec oil pressure increases up to 4 KSC 4

SWITCH ON SLC "Warm-up controller" is required (during cold rolling)

UCB indication

-

Drains before HP control valves, (HPCV-1/2), start opening, 100%.

-

Refer to the SLC logics.

-

HP ESVs and control valves, heating starts and their respective temp. start increasing.

-

Surface and mean temp start rising. Indicated on TSE recorders.

-

Min. temp requirement for HPSV /HPCV is only for absolute cold startups

-

Wait until the mean temperatures of HPCVs come to min. 200 - 250 oC.

-

Upper TSCmargin for admission channel starts droping slowly & after minimum temp are attained, starts improving again.

-

Maintain all TSE margins of Admission channel > 30 K.

-

The metal temperatures of ESV/CV body are within 30oC of the MS temp

-

The heating-up of stop/control valves is complete.

preferably. 5

RAISE speed reference set point to 600 rpm.

KORBA SIMULATOR

-

EHC starts increasing from its initial zero position.

-

Speed controller is in action during turbine rolling.

-

HP CVs start opening.

-

UCB indication.

-

Turbine speed starts rising to 600 rpm at a rate selected by TSE.

-

TSE/UCB indication.

-

The gate valve for turbine barring starts closing when turbine speed comes to 240 rpm. "Gate valve gearing not closed" alarm starts flashing and resets after the valve gets fully closed.

-

Refer to the SLC logics for gate valve gearing.

-

The JOP trips in auto as the turbine speed comes to 540 rpm.

-

Refer to SLC logics for JOPs. UCB indication.

121

6

7

MAINTAIN turbine speed and soak till required HP shaft temp is attained.

RAISE turbine speed reference set point to 3030 rpm.

-

MAINTAIN turbine speed. Soak until required IP shaft temp is reached and SET load reference at 20-40 MW and load gradient at 10 MW /Minute (Max).

KORBA SIMULATOR

-

Start-up curve X-6.

-

HP shaft mean temp becomes steady after 40 minutes (approx)

-

Maintain all TSE margins more than 30 K.

-

Turbine EHC's output starts increasing slowly.

-


-

Turbine control valves (HPCV & IPCV) start opening more.

-


-

Turbine speed starts increasing gradually at a rate decided by turbine stress evaluator.

-

Ensure TSE margins to ensure a min. speed gradient of > 108 rpm /minute to avoid DN/DT protection.

-

8

DT (MS temp. – Mean HP shaft temp) becomes less than the value specified by turbine start-up graphs.

-

"Turbine/Gen. bearing vibration high" and "Turbine absolute shaft vibration high" alarms flash when turbine speed crosses 1400 rpm and 2200 rpm (approx.) and vibration levels increase appreciably and again become normal

-

Critical speeds. (RPM) 1370 1544 2125

Bearing temperatures display an upward trend

-

DT (HRH steam tempMean IPS temp) becomes less than the value specified by turbine startup graphs.

-

If vibrations are already on higher side before the critical speeds, DO NOT ROLL and soak at 600 for some more time until vibrations become normal. Start-up curve X-7.

122

-

-

CHECK all the turbine / generator parameters before synchronisation.

-

Load controller is set at 2040 MW to ensure speed controller transfers to load controller after synchronising. All bearing pedestal vibration is less than 35 microns.

Load limiter set point must be more than load ref.

-

Refer to the generator loading recommendations.

-

UCB/DAS indications.

-

All relative shaft vibrations are less than 150 microns

-

UCB/DAS indications.

-

All bearing babbit metal temp are less than 80 oC

-

UCB/DAS indication.

-

Bearing return oil flow is normal and temp < 77 oC.

-

To minimise ageing of turbine oil.

-

All casing absolute expansions are within normal range.

-

HPT - < 15 mm. IPT - < 10 mm.

-

Thrust bearing oil filters are clean (not choked).

-

Local checks.

-

Axial shift < + 0.3 mm.

-

UCB indication.

-

Turbine casing top/ bottom temperature is< 30 oC.

-

UCB indication.

-

Condenser vacuum is

-

UCB check.

normal at 0.92 Kg/cm

KORBA SIMULATOR

-

2

-

Gen hydrogen pressure is normal at 3.5 KSC

-

Local/UCB check.

-

Stator water flow is More 3 than 27 m /Hr.

-

Local/UCB check.

-

Stator water specific conductivity is less than 5 micro mho/cm.

-

UCB check.

-

Seal oil to hydrogen DP is 2 normal (1.2-1.50 Kg/cm ).

-

UCB check.

123

GENERATOR SYNCHRONISATION 1

ACTION

CHECK all the generator Parameters are healthy

OBSERVATION

-

Stator cooling water flow more than 21 T/Hr.

-

UCB indication

-

Stator cooling water temp less than 40 oC.

-

UCB indication

-

Cold end hydrogen temp less than 40 oC

-

UCB indication

-

Seal oil pressure at turbine and 5.0 KSC

-

UCB indication

-

Seal oil pressure at exciter end 5.0 KSC

-

UCB indication.

-

Seals oil D.P. between1.2 1.5 KSC

-

UCB indication

Generator stator water specific conductivity is less than 5 µ mho/cm

UCB indication. Alarm: 12 µ mho/cm Trip: 20  mho/cm

Gen. hydrogen and stator water coolers are charged and ''Clarified water pressure to hydrogen & stator water coolers low'' alarm is not on. 2

CHECK before closing the field breaker before synchronisation

KORBA SIMULATOR

REMARKS

Local operation. Remote function.

-

Turbine RPM is more than 2980 rpm. Generator isolators are closed from switchyard.

-

UCB & switchyard operator's responsibility/ UCB indication

-

Generator excitation control is on REMOTE.

-

Field breaker does not close from UCB if control is on local.

-

Generator excitation control is on MANUAL OR AUTO.

-

UCB indication.

-

AUTO/MANUAL excitation controllers are on HOME position.

-

Associated white lamp is ON. If not, lower it down to home position.

124

3

4

CLOSE the generator field breaker.

-

Generator field breaker gets closed & Generator voltage increases to 10 KV, 15.75 KV approx. on manual / auto excitation control, respectively.

-


-

Field current and voltage also increases 700 A & 90 V respectively

-

UCB indication

RAISE generator excitation manually, to raise gen. voltage. -

-

Generator voltage comes to 15.75 KV approx.

UCB indication.

Field current and voltage increase to 900A & 105V respectively.

UCB recorders.

Generator gas and rotor winding temperatures start increasing.

Cold gas temp. (HI)

Alarm 47oC

Hot gas temp. (HI)

52oC

75oC

Rotor wdg. temp. (HI)

85oC

110oC

5

CHECK all the generator voltages (phase to phase).

-

6

SWITCH-ON the synchroscope to CHECK mode.

-

-

Alternatively synchroscope is put on Check mode and auto synchroniser can be switched on.

7

ADJUST turbine speed reference to match generator freq with the grid (running).

KORBA SIMULATOR

Maintain all temps within LIMITS.

Trip

All the three phases should read equal voltages

-

UCB indication

IN-COMING/RUNNING voltages and frequencies start showing on their Corresponding meters.

-

UCB indication & operation.

-

Synchroscope needle starts rotating at a rate proportional to difference between the generator and grid frequencies.

-

If the direction of rotation is clockwise the incoming generator frequency is higher than the grid & vice-versa.

-

Incoming and grid frequencies should become equal.

-

Synchroscope indications.

125

-

8

9

ADJUST generator excitation to match the gen. voltage with that of grid.

CLOSE the generator breaker when the check lamp is green.

RAISE speed reference slightly to increase Gen load, immediately after closing the generator breaker.

KORBA SIMULATOR

-

Incoming freq. must be higher than that of grid before synchronising.

-

Grid and generator voltages start matching.

-

UCB/synchroscope meter readings.

-

As synchroscope needle comes to 11'O clock position (clockwise), the green CHECK lamp comes on & the red lamp goes off. At 12' O clock position the check lamp goes off and red lamp comes on again.

-

With synchroscope on check mode the generator can be synchronised (breaker closed) only when the green lamp is on.

-

''Generator Breaker'' gets closed, if all parameters are matching during the ''close'' command.

-

If the breaker fails to close.'' Gen. Breaker Trip'' alarm comes on. re-set and try again.

-

''Generator motoring'' alarm comes on.

-

Synchroscope needle gets locked in 12'O clock position.

-

-

Generator line charging MVAR (approx.-80 MVAR) indication comes on.

-

9A INCREASE Starting Device to 100% 10

Synchroscope needle slows down as the frequencies match.

Starting device comes to 100 %.

Synchroscope red lamp stays "ON"

Power factor becomes leading for some moments and becomes unity again depending upon the gen. Load and excitation. UCB indication.

-

Turbine load increases to 20 MW approximately.

-

-

''Generator motoring'' alarm clears off.

-

Speed reference can be operated from generator desk if the ATRS selector switch is on UCB mode. UCB indication

126

-

11

12

RAISE excitation auto set point until the excitation null voltage becomes zero and TRANSFER excitation to auto.

CHECK all the generator parameters are OK and all phases show equal currents.

-

Excitation null voltage becomes zero.

-

UCB indication

-

UCB indication.

-

Automatic voltage regulator gets transferred to Auto.

-

Generator winding temperatures less than 85 O C (alarm.)

-

KORBA SIMULATOR

''Speed controller'' transfers to 'Load controller'' after some time delay.

Generator transformer winding temp less than 90 O C (alarm.).

Manual channel backs the auto channel if AVR is on.

-

UCB indication.

-

UCB indication.

-

Rotor winding temp are less than 85 O C (alarm).

-

UCB indication.

-

Gen. cold gas temp is less than 47 O C (alarm).

-

UCB recorders.

-

Hydrogen cooler inlet water temp is less than 36 OC (max.)

Local/DAS check.

-

Hydrogen cooler outlet water temp is less than 43 OC. (max.).

-

DAS/Local check.

-

Stator water temp at the inlet of stator is less than 44 O C (maxi.).

-

DAS/Local check.

-

Stator water outlet temperature is less than 70 OC. (max.)

-

UCB/Local check.

127

UNIT SUPPLY CHANGEOVER FROM STATION TO UAT 1

2

ACTION

CHECK before changing over 6.6 KV bus supply station to unit auxiliary transformers.

SWITCH-ON synchroscope to CHECK mode.

REMARKS

-

Unit load is more than 40 MW

-

UCB check.

-

All HT buses incomer breakers from UATs are in SERVICE/REMOTE position.

-

Local operation. Must be done before closing field breaker.

-

UATs (A&B) on load, tap changer gearbox oil levels NORMAL.

-

Local check.

-

UATs conservator tank oil level ADEQUATE.

-

Local check.

-

UATs cooler cubicle power supply is normal.

-

From TG MCC.

-

UATs breather silica gel colour NORMAL.

-

Local check.

-

UATs mulsifire system AVAILABLE. Its air pressure and water pressure NORMAL.

-

Local check/operation.

-

RUNNING/INCOMING voltage comes on and indications come on.

-

UCB indication. (Synchroscope switch CS-1006, S20 and CS-1007, S26 for bus A & B respectively).

-

KORBA SIMULATOR

OBSERVATION

Unit synchroscope red lamp comes on and needle comes to its zero vertical position.

128

3

4

5

6

ADJUST OLTC (on load tap changer) of the UAT (A or B) to make incoming voltage equal to running voltage.

CLOSE UAT (A/B) incomer to Unit bus.

Immediately OPEN the station breaker.

ADJUST OLTC & MAINTAIN Unit bus (A/B) voltage at 6.6 KV.

NOTE:

-

Synchroscope green lamp comes on after the two voltages are matching

-

Without the green lamp CHECK that associated breakers cannot be closed.

-

Incoming/running voltage and frequency indications match.

-

UCB/Synchroscope indication.

-


-

UAT incomer to bus breaker gets closed.

-

''Unit/Station transformers paralleled'' annunciation comes on.

-

UCB annunciation Generator panel

-

Station breaker opens up.

-


-

''Unit/Station transformers paralleled'' alarm clears off.

-

UCB annunciation.

-

UAT winding temperature starts rising.

-

Alarm 85 0C UCB indication

For changing-over the supply from UATs to station or station to UATS use appropriate synchroscope switches. OLTC operation of station transformer is not simulated. In the reference plant the same is operated from CSSAEP panel located in UCB-1.

KORBA SIMULATOR

129

LP HEATERS CHARGING 1

ACTION

CHECK these conditions are satisfied before charging the LP heaters.

OPEN LPH-1 Extraction steam block valve ES-1.

Generator load is at least 40 MW.

-

UCB check only.

-

All LP heaters are CHARGED from waterside and their bypass valves are closed.

-

Local check and local function.

-

All LP heaters airline to condenser, are OPEN.

-

Air vents not simulated

-

Local operation, not simulated. Local operation/check.

-

-

3

OPEN LPH-2 extraction block valve ES-2.

KORBA SIMULATOR

REMARKS

-

-

2

OBSERVATION

-

All pneumatic drain valves are OPERATIONAL & on REMOTE. LPH-1 extraction block valves opens.

Condensate temperature across LPH starts rising. LPH-2 extraction block valve goes open

-

-

UCB operation.

-

DAS/Local check.

-

UCB indication

-

Associated line drain valve DW-83 starts closing after the extraction block valve opens 100%.

-

Interlock.

-

LPH-2 alternate drain to condenser HD-14 starts closing.

-

Interlock.

-

"LPH-2 level low" alarm clears off.

-

UCB annunciation.

130

4

5

OPEN LPH-3 extraction block valve ES-3.

INSTRUCT local operator to throttle all LPH's airlines to condenser and check LPHs levels.

-

LPH-2 normal drain valve HD-11, starts modulating to maintain the level.

-

Associated Green/red indication come on.

-

Condensate temperature after LPH-2 starts rising (DAS check).

-

Levels can be monitored locally only.

-

LPH-3 extraction valve ES-3 goes open 100%

-

UCB indication.

-

Associated line drain valve DW-80 starts closing after ES-3 opens 100%.

-

Interlock.

-

Alternate drain valve HD-19 starts closing.

-

Interlock

-

"LPH-3 level Low" alarm clears off.

-

UCB annunciation.

-

LPH-3 normal drain valve HD-16 starts modulating to maintain the LPH-3 level.

-

Associated green and red lamps start glowing.

-

Condensate temperature across LPHs starts rising.

-

DAS/Local check.

Airlines can be fully isolated after 80 MW load.

It is preferable that all feed heaters be evacuated at least once in the shift by opening their respective side air vents to condenser

LPHs levels are maintained within alarm limits

KORBA SIMULATOR

131

HP HEATERS CHARGING 1

ACTION

OPEN extraction steam block valve ES7 to Deaerator. (Extraction to DA is charged immediately after 40 MW)

-

OBSERVATION Extraction block valve ES-7 opens 100%.

Associated line drain valve DW-79 closes 100% -

De-aerator pressure increases to 4 Kg/cm (approx.)

2

3

ADJUST Deaerator pre. set point to 35% ( 3.5 KSC) & release its control to auto.

CHECK before charging the HPH(5&6).

-

UCB indication.

-


-

At higher loads DA pressure varies with IPT exhaust pressure.

2

-

D/A pressure set point is provided over D/A pr. controller.

-

Use M/A release

-

D/A pre. controller valve starts closing if extraction steam pre. is >3.5 KSC.

-

UCB indication

-

Unit load is more than 120 MW.

-

UCB check only

-

Give ''In-Service'' command to HPHs after opening vents on the feed water lines of HP heater.

-

KORBA SIMULATOR

REMARKS

HPHs inlet/outlet valves (FW-43/44/46/47) are OPEN and individual bypass valve FW-45/48 are CLOSED.

-

HPHs group bypass valves are IN-SERVICE position and "HPHs bypassed" alarm is NOT On.

-

FW-34/35, the group bypass valves can be operated (deenergised) from UCB. And opening of pressurising valve locally cause group bypass to open, in case they are not open previously)

-

All HPHs shell drains are OPEN.

-


132

-

4

OPEN HPH-5 extr. steam block vlv ES-5.

6

OPEN HPH-6 extraction steam block valve ES-6.

INSTRUCT local operator to close all feed line vents and shell drains of the HP heaters.

-

Local operation. Not simulated

-

Extraction steam block valve ES-5 opens 100%.

-

UCB indication.

-

After ES-5 is open, extr. line drain DW-73 closes.

-

Interlock.

-

HPH-5 alternate drain to condenser HD-31 closes

-

Refer to the associated logics.

-

"HPH-5 level low'' alarm clears off. HPH-5 normal drain to D/A starts modulating to maintain the level.

HPH level start building-up. Level checks local only.

-

5

All HPHs airlines to condenser isolating valves are open.

-

Feed water temp after HPH5 starts increasing.

-

DAS/local indications.

-

Extraction block valve ES-6 opens 100%.

-

UCB indication.

-

Extraction line drain DW-74/75 valves close.

-

UCB indication. Interlock.

-

HPH-6 alternate drain to condenser closes and ''HPH-6 level low'' alarm clears off.

-

Interlock. UCB annunciation panel indication.

-

HPH-6 normal drain to D/A HD-51 starts modulating to maintain HP heater level.

Level checks local only.

-

Feed water temp after HPH-6 starts increasing.

-

DAS/local indications.

-

NOTE: HPH-6 drain to HPH-5 can be charged, provided extraction steam pressure to HPH-5 is more than 3 KSC and there is no ''level high'' command in HPH-5 (Block valve HD-39 can be opened).

-

UCB operation & ckeck.

NOTE : Isolating valve of Group Bypass charging line (pressurising line) locally has to be opened. This only causes group bypass to operate after some time. ''HPHs bypass'' indication is from the group bypass valve limit switch, not from the solenoids.

KORBA SIMULATOR

133

SUPERHEAT AND REHEAT STEAM TEMP. CONTROL

ACTION

OBSERVATION

REMARKS

1

OPEN super-heater and reheater spray water header block valves.

-

Super-heater block valve S-80 and re-heater block valve R-40 is opened 100%.

-

RH block valves: DC solenoid operated and the SH block vlv are motor operated.

2

OPEN S/H and R/H attemperation block valves, one stream A & B.

-

S/H attemperation block valves S-83/S-86 on stream-A & S-89/S-92 on stream-B open 100%.

-

Associated red lamps are on. One block valve each on stream A&B is to be opened.

-

R/H attemperation block valves R-43/R-46 on stream-A and R-49/ R-52 on stream-B open 100%.

-


-

Manual/auto release flickering stops, enabling the releasing of associated controllers to auto.

-

UCB indication.

3

OPEN Manual isolating valves after control valves (A & B)

-

Valves S-88, S-85, S-91, S-94 and R-48, R-45, R-51 and R-54 are open

-

Local operation. Not simulated. DAS indication.

4

OPEN S/H attemperation control valves.

-

S/H attemperation flow increases.

-

UCB recorders.

After attemperation temperature starts dropping and the difference between before & after attemperation starts increasing.

-

UCB recorders. Maximum diff.

-

permissible is 50 oC.

5

ADJUST S/H outlet temp set points to 90% each. (540 oC).

-

S/H temperature set points are provided over respective controllers.

-

M/A release must be pressed for manual to auto transfers.

-

ADJUST hot reheat temp set point to 90% and biasing set point to 50%.

-

Hot reheat temperature set point is provided over burner tilt controller.

-

Auto controller for SH/HR temp trips to manual if BFP DP across FRS is > 20KSC

KORBA SIMULATOR

134

-

RELEASE burner tilt controller & SH/RH steam temperature controllers to AUTO.

NOTE :

-

Burner tilt controller and SH/RH control valves modulate to maintain set steam temperature.

Hot reheat temperature should be primarily controlled by controlling firing rate. If firing rate cannot be reduced, burners can be tilted downwards, provided boiler loading is adequate and furnace flame is stable. THE REHEATER ATTEMPERATION MUST BE RESORTED TO IN THE LAST. The re-heater attemperation causes a great loss in the cycle efficiency, as the HRH steam does not do any work in the HP turbine.

KORBA SIMULATOR

135

SOOT BLOWER OPERATION 1

ACTION

CHECK these conditions before soot blowing.

OBSERVATION

REMARKS

- Boiler load is more than 75%.

- Furnace stability criteria.

- Furnace flame is STABLE.

- If not, cut in oil support.

- Soot blower MCC power supply (220V) is ON.

- Supply is provided in the Boiler MCC panel.

- Soot blowers control supply (415V) A/C) is ON. - All blowers are in 'HOME' position.

- No red lamp indication should be 'on' on the UCB panel.

- Soot blower header drain valves are in OPEN position.

- UCB operation

- Main steam inlet isolating valves to soot blower system, SB-108/SB-109 are CLOSED.

- SB 109 is UCB operated.

- SB 108 is locally operated (not simulated).

KORBA SIMULATOR

- Soot blower steam pressure control valve SB-4 (pneumatic) is OPERATIONAL and its impulse/root valve is OPEN.

- Root valve not simulated. Pneumatic pressure control valve maintains approx. 20 2 Kg/cm of steam pressure tapped off from SH header No. 10.

- Uni-selector (stepper) relay is in its STARTING POSITION.

- Sequence Complete indication is ‘ON’ on the soot-blowing panel.

136

- Soot blowers' selection switches should be on AUTO or BY-PASS positions as per soot blowing requirements.

- Individual switches are provided on the UCB soot-blowing panel.

- Individual blowers' overload - Local operation from tripping must be RESET'. (If individual blower operated) MCC. Not simulated.

2

OPEN electrical isolating valve SB-109 completely.

- Blower control panel selector switch is on 'PANEL' position.

- UCB operation

- SB-109 opens up 100%

- UCB indication lamp comes on.

- Steam pressure and temperature gradually raise to approx. 20 Kg/cm 2 and

- 'Pr. Low' and 'Temp. Low' indication gets reset on the soot blowing panel.

280 oC respectively. -

3

OPEN manual isolating valve SB108 gradually for warming up lines. CHECK steam temperature in all the four drain' points by operating the selector switch provided on the panel. CLOSE all the four drain valves once the required steam temperature is achieved.

- Temperatures in all fourdrain lines must be greater than 220 oC each.

- Temp low is a sequence interrupting protection/ condition.

- All four-drain valves on soot - UCB operation. blower header are CLOSED. Drains closed is an Interlock/ Permissive for sequence starting.

KORBA SIMULATOR

137

4

PUSH ' Reset' Push Button on UCB soot blower panel and then SEQUENCE START push button.

- ''Soot blower system trouble'' alarm clears off

- UCB indication.

- 'Pressure/temp low' alarms get reset.

- UCB indication on soot blower panel.

- ‘‘Sequence On’’ indications come on. Wall soot blower leaves its 'HOME' position and advances to its operating position (provided it is selected on (AUTO).

- Red indication comes on the soot blower panel.

- Steam header pressure dips slightly as the soot blower opens.

- Steam pressure maintained by the Pressure control valve.

- After approximately 1.5 min. the blowers retracts to its home position.

- RED indication goes off.

- Next blower on Auto comes into service with a time delay of 3 seconds and sequence continue. One blower at a time.

- Total 56 nos of wall blower are provided in the boiler, each with a blowing time of 1.5 minutes.

NOTE : 1. LRSBs are numbered from 57 onwards up to 80 for soot blowing in platen S/H, final S/H, horizontal S/H and economiser respectively. 2. Blowing time for LRSBs is approx. 8 min. and blowing operation for LRSB continues right from the moment it leaves its home position unlike wall blowers in which case, blowing starts after the blower reaches blowing position. 3. APH soot blowing is also possible through auto sequential operation besides independent/manual operation with aux. steam. Their total blowing time is approx. 45 min. and blowing takes place only during the forward stroke. 4. Recommended frequency for wall blowers is once a shift, for LRSBs it is once a day and for APH soot blowers during oil firing or whenever the gas/air DPs across APH exceed the normal value by 30-40 mm wcl.

KORBA SIMULATOR

138

KORBA SIMULATOR

139

UNIT COLD START-UP

KORBA SIMULATOR

140

KORBA SIMULATOR

141

UNIT COLD START UP PROCEDURE 1.

ACTION

CHECK all pre-start conditions are satisfied before starting the unit from cold.

-

OBSERVATION -

Refer to the PTW record book and unit controller's logbook.

-

Local checks.

-

Local Checks. Not simulated.

-

Local checks/ operation. Not simulated.

Ash hopper sealing/ flushing water Supplies are AVAILABLE. - Service/Instrument Air Pr. 2 ADEQUATE (7-8 kg/cm ).

-

HP/LP water pump are ON Not simulated. Local operation. UCB indications.

-

-

Shift-charge’s responsibility.

-

-

-

All work permits on main boiler, all electrical panels, all aux. Systems are CANCELLED All man/materials are REMOVED from equipments and site. Lube oil levels in bearing and MOT/oil tanks are ADEQUATE. Clarified/Raw water pumps are ON and water systems are LINED-UP.

-

2

3

KORBA SIMULATOR

Water treatment division has been INFORMED and DM water storage is ADEQUATE.

-

-

Generator hydrogen filling system is LINED-UP.

-


-

Generator seal oil system is line-up.

-


Valves AS-5, AS-6 AS-8, AS9, AS-10 are OPEN.

-


All aux. steam (unit) supply valves AS-11/ 12/ 13/ 14/ 16/17/18 19/32 are OPEN.

-

Local operation.

-

UCB indication.

OPEN all drains/ vents on aux. steam header & line-up unit aux. steam hdr for charging. -

OPEN AS-31, the interconnection between aux. steam hdr of U#1, U#2, U#3.

REMARKS

-

Unit aux. steam pressure 2 starts rising to 13 kg/cm

142

-

4

5

CLOSE all associated drains and vents on the aux. steam header

-

INSTRUCT local operator to charge seal oil system and then hydrogen cylinders into generator casing.

-

Aux. steam temperature goes up to 220oC (approx.) All aux. steam hdr drains & vents are closed after the aux. steam header reaches to 2-3 kg/cm

-

DAS/UCB indicated.

-


-

Local/UCB check (If air is filled-up then CO2 must be charged to expel the air and after recommended CO2 purity is achieved hydrogen filling is started.

2

Hydrogen pressure in the generator starts rising and 2 comes to 3.5 kg/cm (approx.) H2 pressure will be 2

raised to 3.5 kg/cm only after achieving the gas purity. Before that pr. is to 2 be maintained 2 to 3 kg/cm to reduce H2 consumption. Seal oil to H 2 DP is to be

UCB indication. Local operation. Not simulated.

maintained at 1.2-1.5 2 kg/cm 6

ENSURE before boiler filling, all preparations have been made

At least one condensate and one boiler feed pump is LINED-UP and READY for operation.

-

Refer to the respective operation instruction.

-

Condensate and feed water systems are LINED UP.

-

Local/UCB checks.

Economiser and superheater air vent are OPEN


Drum air vents and SH/RH start up vents are OPEN fully.

Local UCB operation.

Drum emergency blow-down valves B-82, B-83 and intermittent blow down valves B-105, B-106 are CLOSED.

KORBA SIMULATOR

UCB operation.

143

CBD and low point drains (LPDs) are CLOSED.

HP/LP chemical dozing stations are LINED-UP & AVAILABLE. Boiler Economiser recirculation valves E-27, E-29 are OPEN. Aux steam connection to D/A, AS-64 & AS-16 is OPEN. D/A pressure set point is at 10%-15%. (Corresponding to 1.5 kg/cm2 DA pressure) D/A storage tank heating valves AS-76, AS-77 are OPEN.

7

8

START one CEP for D/A filling, after filling the condenser hot well.

CHARGE D/A feed storage tank heating by opening AS-78 slightly and transfer D/A pr controller to auto control after DA pressure is 1.5 kg/cm2.

KORBA SIMULATOR

Local operation (Remote functions). LPDs not simulated. UCB operation & local checks.

UCB operation. Not simulated.

UCB/Local check.

UCB operation.


Isolating valves of D/A pr. controller, S-66, AS-67 are OPEN.


Deaerator level starts increasing and comes up to 1500 mm wcl.

UCB indication

Maintain D/A and Hotwell levels at 1500 mm & 500 mm wcl respectively

UCB Operation.

D/A feed storage tank water temp starts rising.

DAS indication.

D/A pressure starts building up to 1.5 kg/cm 2, gradually.

AS-78 not simulated. Local operation.

144

9

START one BFP to fillup the boiler by operating low range feed control valve.

DA pressure controller maintains the set pressure.

Set point can be raised to 20% and 40% at TG loads 40 MW and 80 MW respectively.

Drum level starts increasing gradually.

UCB/DAS/Local indications.

Maintain drum level at (-) 60 mm wcl before boiler lightup

10 START one LP dozing (hydrazine) pump and adjust its stroke as required, after feed water temp comes to 150oC.

11 START one HP dozing (phosphate) pump if drum water pH value is lower than required.

12 ENSURE all pre-start Conditions for purging and light up are satisfied.

KORBA SIMULATOR

Hydrazine concentration before economiser starts rising after some time (max. 0.05 ppm).

Boiler fill pump connections to DA economiser, SH and boiler W/W ring header for direct fillin, is not simulated. UCB checks.

Oxygen in feed water to be maintained 0.007-ppm max.

As per boiler manufacturer’s recommendations.

PH value of drum water to be maintained at 9.0-9.4.

UCB indication or chemist's recommendations.

Residual phosphate to be maintained at 5-10 ppm. at full load.

UCB check and indications.

Both APHs are IN-SERVICE

UCB operation.

One set of ID &FD fans and associated air & flue gas systems are lined-up and IN SERVICE.

Refer individual operating instructions.

145

13 START furnace purging.

14 LIGHT-UP the boiler with AB elevation oil guns Initially, CD elev. Guns can be taken after drum Pr reaches up to 2 KSC

All wind-box dampers are OPEN.

UCB/Local checks.

All purge per missives are ON.

UCB checks operation.

Two HFO and one light oil pumps are IN-SERVICE.

Local operation. (Remote functions).

Aux. steam to atomising steam hdr, HFO heating and SCAPH, is CHARGED.

Local operation. (Remote functions)

All drum. SH, RH air & startup vents and drains are OPEN.

Start up vents is UCB operated.

Furnace probes are INSERVICE positions. (100%)

UCB operation.

MRF (A&B) are reset after five minutes.

"MFR TRIP” alarm goes off.

First cause of trip resets.

UCB indication FSSS - console.

Drum metal temperature starts increasing, gradually.

DAS indications.

Rate of saturation temp rise to be maintained 110 oC per

DAS indications.

hour (maximum). Drum differential temp to be maintained below 50 oC

DAS indications.

(maximum). 15 SWITCH-ON the vapour extractor fan of the MOT & SGC OIL to auto.

"Green ON lamp comes on" and associated alarm clears off.

Aux. oil pump-1 and Jack oil pump no.-1 become on.

UCB check only.

UCB operation /check.

OR

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146

SWITCH-ON Individual SLCs on the turbine console manually.

16 ENSURE all pre-start checks for vacuum pulling are over.

17 OPEN AS-80/81 and CA-5/6 of one starting ejector for pulling vacuum and transfer seal steam pressure controller to auto.

Turbine gate valve gearing opens-up and turbine speed goes up to 110 rpm (approx.)Oil temperature control valve starts modulating. All other valves under SLCs start modulating as per their logic programme. Condenser water box priming ejector's steam and airside valves are OPEN.

Local operation. (Remote function). Condenser air valves not simulated. UCB operation.

Condenser vacuum breaker valve is CLOSED & Water sealing is AVAILABLE.

UCB operation check.

Gland sealing header/ line drains are OPEN.

UCB operation.

Condenser vacuum starts building up gradually to 0.7 Kg/cm2

Vacuum builds up to 0.92 2

Kg/cm

Turbine speed increases up to 220 rpm. (Approx.)

KORBA SIMULATOR

UCB indication.

Condenser CW inlet/ outlet valves are OPEN.

Gland seal steam pr. controller transfers to auto 2 and maintains 0.01 Kg/cm (g) of seal steam pressure. 18 OPEN AS-52/ 54 of one main ejector and cut out the starting ejector.

UCB indication.

UCB operation. Any one starting ejector can be taken in service.

UCB check only. Associated alarms are reset.

UCB indication Main ejector air valves are not simulated. UCB indication

147

19 OPEN all Main steam CRH and HRH drains to BD tank.

20 CLOSE all drum SH and RH air vents after the drum pr. comes 2 to 2-3 Kg/cm and throttle start-up vents.

21 At a drum pr. of 6 Kg/cm2 , OPEN integral bypas valves to main steam stop valves, for MS line Heating, gradually.

22 ENSURE all prestart checks for charging HP/LP Bypass system & Rolling turbine are over.

Valves DW153/154/155/156, DW171/172/173/174 and' DW164/165/141/142 are OPEN. SH-RH and drum air vents closed.


S-28, S-23, R-15 and R-20 are throttled.

UCB operation.

Drum pressure starts rising.

UCB/DAS indication

Valves MSBP - 1 and MSBP3 are to be opened 100%.

UCB/DAS indication.

Valves MSBP-2 and MSBP-4 are to be throttled & opened gradually, after MSBP-1/3 are fully open.

UCB operation Interlock.

All turbine line drains to flash tank are OPEN and to BD tank are CLOSED.

UCB operation. Refer respective operation instructions.

Turbine starting-device is at 0% position and UTRs (unit trip relays) are RESET.

All turbine and generator parameters are NORMAL.

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UCB indication

UCB operation GTRs must be in reset position and stator water conductivity and flow must be normal before one can reset UTR UCB/DAS check.

148

TSE and Frequency influence on EHG are NOT OFF.

UCB check only.

Speeder gear is at 100% and EHC 'NOT FAULTED' and is 0%

UCB operation, Electro hydraulic Governor is at selected.

All HP/LP bypass set points are ADJUSTED as per procedures.

Refer to the corresponding Operating instructions.

Turbine SLC drains is ON. 23 CHARGE MS lines 100% and raise boiler firing to raise steam parameters to 40 KSC of MS Pr. and 300 oC

UCB operation.

Valves S-42, S-64 are being OPEN 100%.

-

UCB operation.

-

The bypass valves MSBP 1/2/3/4/ are automatically closed.

-

Interlocks.

-

HP/LP bypass valves start modulating to maintain set steam parameters, to be adjusted upwards.

-

UCB operation.

-

Steam temperatures must be maintained at minimum values as indicated to minimise soaking times.

-

Refer to the turbine start-up curves.

of MS temp (mini), before turbine rolling. CLOSE start-up vent valves and SH header drain valves.

-

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Steam parameters start rising, depending upon firing rate and HP/LP bypass operation.

149

24 At MS pressure 25-30

-

HP stop valves open at 42% of starting device position.

-

IP stop valves open at 56% of starting device position.

UCB Observation.

-

Aux. secondary oil pressure

-

UCB check only

UCB check only

2

Kg/cm RAISE starting device to 70% position and SWITCH ON the SLC warm up controller.

increases to 3 Kg/cm (approx.)

25 RAISE speed reference to 600 RPM and SOAK turbine at 600 RPM until required mean HP shaft temp is attained (speed-up criteria)

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UCB operation.

2

-

Start-up oil pressure becomes zero.

-

-

Warm-up drains after HP stop valves start opening for warming up HPCV and close after set TSE margins are achieved.

-

UCB check only. Warm-up drain valves must be put on auto & set point to be adjusted by the operator, as required.

-

HPSV & HPCV mean temperatures increase gradually to 220oC.

-

-

Turbine speed gradually increases to 600 RPM.

-

UCB check only

-

Gate valve gearing starts closing at 240 rpm.

-

-

Jack oil pump trips at 540 rpm

-

-

HP shaft mean temperature starts increasing gradually.

-

Interlock, if corresponding SLC is on. Interlock, if corresponding SLC is on. TSE recorder’s indications, in the UCB.

150

ENSURE all pre-start checks for rolling up to the rated speed and Synchronising, are completed.

-

All TSE margins are more than 30oC.

Check TSE recorders & Indicator

All Generator conditions are HEALTHY.

UCB/DAS checks.

All differential expansions are less than MAXIMUM (+ve/-ve)

UCB/DAS checks.

HP turbine and LP turbine exhaust temperatures are less than MAXIMUM.

27 RAISE turbine speed reference to 3000 rpm without stopping and soak until required IPT mean shaft temp is reached. (Loading criteria)

-

UCB/DAS indications are below 480 oC AND 90oC respectively.

All casing (HP & IP) top bottom temp differences are less than 35 oC.

UCB/DAS indication.

All bearing temp are less than 90oC.

UCB/DAS checks.

All bearing and shaft vibrations are less than 30 & 100 microns.

UCB/DAS checks.

Generator stator water and hydrogen cooling systems are CHARGED.

Local operation (Remote functions)

Turbine speed goes up to 3000 rpm gradually, depending upon the TSE margins available

UCB indications.

Ensure all vibrations are below the maximum limit. AOP cuts-out at 2950 rpm if SGC oil is on or switch off the AOP maually IPS mean temperature increases gradually to 275 OC KORBA SIMULATOR

UCB indication. Interlock.

Refer to TSE recorders. 151

28 SWITCH-ON the load controller and load gradient controller. CLOSE the field breaker and ADJUST the excitation to the required Gen. voltage.

Load gradient and load controller become on.

UCB check only. Load limiter to be set more than load reference.

Ensure excitation M/A channels controls are at MINIMUM, (HOME) Position

29 RAISE starting device to 100% and load ref. & load gradient set points to 20 MW & 5 MW/MIN respectively.

30 Close the Bus isolator and Generator isolator and switch on the synchroscope and synchronise the Gen. with the Grid. -

31 LINE-UP and CUT-IN one PA fan and any one mill and feeder, RAISE load to 40 MW.

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Generator voltage builds up to 15.75 KV.

UCB indications.

Aux. Secondary oil pressure goes up to 4.5 Kg/cm 2 (approx.)

UCB indications.

All turbine and generator parameters to be maintained within their normal, Specified limits.

Local/UCB check.

Generator breaker gets closed.

Generator block loading is to be done to avoid tripping of the gen. on "REVERSE power" protection.

-

UCB operation.

-

Refer to synchronising Procedures.

-

EHC speed controller transfer to load controller, after some time delay.

-

Refer to EHC control logics.

-

Turbine load increases to 40 MW.

-

UCB operation.

-

Generator voltage to be maintained at rated value of 15.75 KV.

-

Refer to the generator Capability curves.

152

32 LINE-UP and CHARGE all L.P. heaters one by one. CLOSE all turbine drain & close HP/LP bypass system.

32 CUT-IN another pulveriser and RAISE firing. RAISE load on the unit.

34 CHANGEOVER from station supply to unit aux. transformers (U.A.T.s), and CHARGE unit aux. Steam header from main steam lines. CHARGE D/A extraction from the IP turbine.

-

Condensate temperature to D/A starts increasing..

-

DAS points.

-

Main steam pressure increases slightly.

-

UCB indications.

-

Unit loading increases gradually up to 60 MW.

-

UCB indication. Load must follow the MS pressure

-

MS pressure keeps Increasing.

-

Main steam pressure 2 Comes to 70-80 Kg/cm

-

UCB indications.

-

Unit bus voltages to be maintained at 6.6 KV with tap changers.

-

Refer to the bus changeover procedures.

-

Aux. steam pressure to be

-

Refer to the operating Instructions. Aux. Steam header can be charged only after MS pr is 50 Kg/cm2 or more.

maintained at 14-15 Kg/cm 2 -

D/A pressure modulates with the unit load.

-

Interlock. 35 START the second set of ID, FD, PA fans & BFP and START the third pulveriser feeder and RAISE load to 150 MW. CHARGE high-pressure heaters one by one. -

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MS pressure to be maintained at 148 Kg/cm after 100 MW.

Unit load increases up to 150 MW.

-

UCB operation.

-

UCB check only.

2

153

-

36 CUT-IN 4th pulveriser and raise load to 200MW

37 TRANSFER all ID, FD, PA fans controls and BFP scoop controller to auto.

Feed water temperature rises up gradually.

-

DAS points.

Unit heat rate improves gradually.

-

DAS point.

-

Unit load increases up to 200 MW.

-

UCB operation.

-

MS/HRH steam temperature to be maintained at 535 oC.

-

UCB operation.

-

ID fan vanes transfer to auto & maintain set furnace vacuum.

-

UCB operation. Furnace draft of -5 to –10 mm wcl is to be maintained

-

Boiler master controller out put generates oxygen set point.

-

FD fan blades modulate to maintain Oxygen in flue gases.

-

PA fan vanes transfer to auto & maintain set PA hdr. Pressure.

-

BFP Master maintains the set feed water DP across the feed regulating station.

PA header pressure of 750 mm wcl is to be maintained. -

Feed regulating station DP is to be maintained. at 5-8 2

Kg/cm 38 ENSURE the mill PA flow and temp control on auto.

-

Auto lamp of both the controller is ON.

-

Both the controller must be in auto mode before feeders are put in auto.

39 ADJUST raw coal feeders' biasing to 50% and the Fuel Master Controller’s output, as per requirement.

-

The feeder speed controller's error deviation comes to 0% (biasing may be adjusted to get dev. 0% for a given fuel master output).

-

UCB check only.

40 ADJUST throttle pressure set point equal to the main steam pressure & SET boiler master's output as required.

-

Error deviation on boiler master comes to 0%

-

Before putting control on auto corresponding error deviation must be zero to avoid hunting.

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-

Errors deviation on fuel master comes to 0%.

41 RELEASE all mill, feeders and fuel master controller to auto.

-

Boiler firing can be adjusted from Boiler Master, manually.

-

UCB operation.

42 ADJUST Unit Master output equal to the T/ G load and set max/min. load limits and load rate on CMC console. RELEASE Boiler master controller to auto and unit control to CMC.

-

Boiler Master controls the boiler firing rate, depending on the unit load demand and throttle pressure set point.

-

Refer to the CMC logics.

-

Unit Master on auto modulates according to the load demand signal from the load dispatch centre.

-

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Before putting Unit Master on auto, unit master’s output to be made equal to the load demand signal from ALDS.

155

UNIT HOT START-UP

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UNIT HOT START-UP PROCEDURE 1

ACTION

CHECK the conditions existing immediately after the unit tripping.

-

Generator/Field breakers are tripped with the corresponding alarms.

-

UATs' supply to unit buses is tripped and station supply takes over automatically.

-

Generator AVR trips to manual mode, automatically with an alarm.

-

-

UCB annunciation.

UCB indications. Inter-lock.

UCB annunciation.

All the turbine stop and control valves are closed.

-

Turbine trip oil, aux. secondary oil, and secondary oil pressure become zero

UCB check only.

-

All LP / HP heaters extraction block valves are closed automatically.

-

UCB check only.

-

All extraction line NRVs are closed.

-

Refer to turbine governing system.

-

Turbine AOP -1 starts automatically (if SLC is on).

-

Interlock.

-

The JOP -1 starts automatically at 510 rpm. (If SLC is on).

Interlock.

-

Turbine gate valve gearing is opened automatically at 200 rpm. (If the SLC is on).

Interlock. Check locally also.

-

HP/LP bypass valves openup if on auto with proper set points, to limiter set position. Condenser vacuum breaker valve may open if tripping is

-

REMARKS

-

-

KORBA SIMULATOR

OBSERVATION

-

-

Refer to Turbine governing system.

UCB checks. Refer to the HP/LP bypass interlocks.

Interlock. Refer to the tripping logic 158

on Fire protection or axial shift.

2

3

ENSURE all the ''*'' marked conditions are fulfilled immediately after a tripping. If interlocks do not act, fulfil the conditions manually.

STOP any one set of ID & FD fans to avoid forced cooling of the boiler. STABILISE and maintain draught & KORBA SIMULATOR

(turbine)

-

SH/RH steam attemperation block and control valves are closed.

-

Interlock. Steam flow < 15% MCR

-

Drum level dips to very low values.

-

UCB check only.

-

All running mills and their feeders with both PA fans are tripped.

-

Refer to FSSS logics and interlocks.

-

HFO and ignitor trip valves are closed automatically.

-

Refer to FSSS logic. UCB check.

-

All HFO guns and ignitors are tripped and their associated oil/steam/air valves closed.

-

UCB check only. Check locally too.

-

Furnace vacuum dips to very low values due to implosion.

-

UCB indications.

-

All wind-box dampers openup after unit tripping.

-

UCB check.

-

''Control interface fault'' or ''Control interface status fault'' or ''Running time exceeded'' etc. alarms are not present.

-

UCB annunciations

-

Any fault lamps (red) on ATRS or SGC console are not ON.

-

If alarms are on, get the faults rectified and cut in the associated system manually.

-

Furnace draught is maintained at -5 to -10 mm wcl.

-

UCB operation.

159

airflow.

4

5

6

7

8

-

Furnace airflow is to be maintained between 30% to 40%.

-

UCB indication

-

Burners to be brought to horizontal position, quickly.

-

UCB operation

-

Boiler MFR (A&B) gets reset after a time delay of 5 minutes.

-

UCB operation.

-

The first cause of unit tripping gets reset along with MFR. reset.

-

Indication on FSSS console.

ENSURE Deaerator Pressure is maintained at 3.5 Kg/cm2 and aux. steam pressure at 14 Kg/cm2

D/A pressure controller must be on auto and pressure set point to be at 34 Kg/cm2.

-

UCB check only.

ESTABLISH condenser vacuum if it has deteriorated on protection.

-

If MS pressure falls below 70 Kg/cm2 aux steam header may be charged other units.

-

Isolating valve of unit PRDS are closed at MS pr. of 50 ata.

-

Cond. vacuum must be more than 0.8 Kg/cm2 before charging HP/LP bypass system.

-

UCB operation.

-

Main steam pressure is to be maintained below 100 Kg/cm2, preferably for hot

-

UCB operation.

Starting device is brought to 0% position

-

UCB operation for turbine resetting.

-

Turnine gets reset.

-

UCB indication

-

Maximum and minimum

-

Refer to the turbine

ENSURE all purge permissive are available and do furnace purging for 5 minutes.

CLOSE HP/LP bypass system to avoid drop in steam pressure

start-up.

RESET generator trip relay and unit trip relays and turbine.

LIGHT UP the KORBA SIMULATOR

160

boiler with the upper elevation guns and a mill if required to hold the MS/HRH temp. CHARGE HP/LP bypass.

steam temp required for hot rolling might be determined from HPCV and HPS mid metal temperatures.

start-up curves XI X7. Roughly steam temperature > (HPCV temp.+ 50 O C)

-

HRH steam temp tend to drop with the charging of HP/LP bypass systems. (Min Required is 480 oC).

9

Roll the turbine to 600 rpm and SOAK for 5 minutes.

Gate valve gearing & JOP cut out of service at 240 and 540 rpm respectively.

-

Interlocks.

10

RISE speed to 3000 rpm and SYNCHRONISE as per procedures.

Load gradient can be raised above 10 MW/min. for loading, however the generator loading recommendations must be adhered to.

-

UCB operation.

KORBA SIMULATOR

-

161

AUTOMATIC TURBINE RUN-UP SYSTEM (ATRS)

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AUTOMATIC TURBINE RUN-UP SYSTEM (ATRS) A successful start-up of the turbine normally requires acquisition and analysis of wide variety of information pertaining to various parameters like speed, steam temperature, vacuum, oil pressure, warm-up condition of turbine and pipelines. Apart from this, it is important to know whether vital auxiliary equipment is on automatic control loop or not. It is an arduous task for the operator to handle and collect so many bits of information swiftly and correctly. Automatic Run-up System performs this task swiftly, accurately and at the appropriate time. The chances of mal-operation due to error, improper judgments of the situation get practically eliminated. Automatic Run-up System relieves the operator of arduous task involving in surveying the various parameters and thus the entire attention is diverted to watching the performance of the main equipment. BASIC CONCEPT The Automatic Run-up System is based on 'Functional Group Control' philosophy, means that the main plant is divided into clearly defined technical sections called functional groups. Each functional group is sub-divided into 'sub-group control' and 'sub loop control' and 'interface control'. It is apparent that each functional group continues to function automatically all the times demanding 'Enabling Criteria' from other functional groups. In case the red 'Enabling Criteria' is not available from neighboring 'Functional Group Control', the system would automatically act in such a manner as to ensure the safety of the main turbine. This method avoids a major difficulty generally encountered in laying down priority and correct sequence of the various steps in single logical chain of events. DEFINITION OF TERMS USED IN ATRS Functional Group Control (FGC) Functional Group Control is the automatic control of a largely independent plant section (functional group) or a process section. This term comprises: • • •

Group controls Sub group controls Sub loop controls

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164

Group Controls (GC) The Group Controls contain the logic for controlling the subordinated subgroup controls. They utilise gating logic. The function of the Group control is to decide when, how many and which of the subordinated group controls should start or shutdown and realise the fault changeover in case of several subgroups Sub Group Controls (SGC) Sub Group Controls contain the sequence logics for switching units ON and OFF, and all the associated auxiliary equipments. Normally, step techniques are preferred for the design of subgroup controls. Sub Loop Controls (SLC) Sub Loop Controls comprise only a part of the automated operation of a functional group or unit. They are always of logic gating design. They may (as in the case of subordinated sub loop controls) form part of a functional group control and be switched ON or OFF by it. Sub Loop controls (with the exception of unit changeover controls) differ from subgroup control in that although they can be switched ON and OFF manually they can only receive direction-dependent commands (control elements HIGHER/LOWER, Motor ON/OFF) through criteria (e.g. automatic controls for auxiliary oil pumps, pressure or level switches). Sub Loop Controls include the unit changeover controls. These come into action when changeover operations are required for units of the same type during fault conditions. In general, changeover controls cannot be switched off directly from their own desk tile. If the design concept calls for a changeover control that can be switched off, a manual-automatic module shall be provided. Command A command is an instruction for a change of status. Protective Logic (PL) Protective logic consists in logic gating between ON or OFF commands with criteria, which serve, to the plant (e.g. boiler interlocking) or the unit (e.g. unit interlocking). Protective logic cannot be switched off. Sequential Control Sequential Control is a control arrangement with Boolean operations, storage provisions and its functions proceeding step by step. Advance to the next step depends on process signals and/or time factors.

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MODE OF OPERATION Each functional group is divided into logical steps arranged in a proper sequence. Prior to the commencement of any step, it is necessary that certain conditions regarding status of plant get fulfilled and the relevant Parameters acquire the desired value. All these pre-conditions are meticulously planned for each step and demanded from the system as 'Enabling Criteria' for next step. ATRS - STRUCTURE AND GENERAL FEATURES

Automatic Turbine Run-up System is essentially organized in two sub-group controls namely Turbine System (SGC Turbine) and Oil System (SGC Oil). These groups in conjunction with wall stress analyser and electro-hydraulic governing system accomplish the various functions. A sub-group control essentially executes a set of steps in a proper sequence. Sub-group control at times envisages a sub-loop control that essentially executes commands based on the availability of 'Enabling Criteria'. Sub-group control for the turbine run up acts directly on: • Sub-loop controls (SLC) for the drains. • Electro-hydraulic Governing System. • Auto Synchronizer

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Sub-group control for the oil directly actuates: • SLC for the DC lube oil pump. • SLC for lub oil System. • SLC for turning gear operation and • Interface devices for selected few pumps.

ATRS OPERATION CONSOLE

According to the pre-determined sequence, SGC & SLC ensure various requirements of control oil, lube oil, oil for hydraulic turning etc. under run-up, shutdown and trip conditions. The sub-loop controllers get switched on and off according to the pre-defined sequence logic built in the SGC. However, the actual execution of command of a SLC takes place only if the enabling criteria for the fulfilment of a particular command are completely satisfied. It is possible to intervene manually at any level namely interface sub-loop control or sub-group control. The enabling criteria at the various level of hierarchy are of different nature. For instance, the enabling criteria at the ‘Interface Level’ envisaged are based on the equipment protection point of view rather than the process consideration. It is also possible to manually start the plant up to any level/status then ask the sub-group control to perform the remaining functions. To facilitate such modes of operations, the sequential logic has been development in such a manner the subgroup control shall quickly skip to the proceeding step done manually and accomplish the steps automatically in the desired logical manner. The SGC Turbine logics for (ATRS) incorporating various steps and criteria required to execute each steps are in the following sections. KORBA SIMULATOR

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KORBA SIMULATOR

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SGC OIL SYSTEM LOGICS

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SUB LOOP CONTROL - AUXILIARY OIL PUMP - 1 2

1. When SLC AOP - 1 is ON AND AOP - 2 trips OR Oil pressure < 4.8 Kg/cm , command is given to switch on Aux. Oil Pump - 1 SUB LOOP CONTROL - AUXILIARY OIL PUMP - 2 2

1. When SLC AOP - 2 is ON AND AOP - 1 trip OR Oil pressure < 4.5 Kg/cm , command is given to switch on Aux. oil Pump - 2 SUB LOOP CONTROL - DC EMERGENCY OIL PUMP 1. When SLC emergency oil pump is ON AND if lube oil pressure < 1.1 2

Kg/cm command is given to switch on EOP. SUB LOOP CONTROL - JACKING OIL PUMP - 1 1. When SLC JOP - 1 is ON AND if turbine speed < 510 RPM, command is given to switch on JOP -1, 2. If turbine speed > 540 RPM, command is given to switch off JOP - 1

SUB LOOP CONTROL - JACKING OIL PUMP - 2 2

With SLC JOP - 2 is ON, if JOP - 1 trips OR if jack oil pressure < 120 Kg/cm , with turbine speed < 510 rpm with a delay of 5 seconds, command is given 1. To switch ON JOP 2 2. To switch OFF JOP 1 3. To switch OFF SLC JOP-1

SUB LOOP CONTROL - TURNING GEAR 1. With SLC turning gear is ON AND if turbine speed < 200 RPM, command is given to open the gate valve gearing. 2. If turbine speed is greater than 240 RPM, Command is given to close gate valve gearing

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SUB LOOP CONTROL: OIL SYSTEM STARTUP OPERATION RELEASES 1. OIL VAPOUR EXTRACTOR (1) OR (2) ON 2. OIL TANK LEVEL ADEQUATE STEP -1 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED CRITERIA FOR STEP - 2 1. STEP-01 COMPLETED

OR

2. STEP-08 COMPLETED AND TURBINE SPEED < 510 RPM

OR

3. STEP-11 COMPLETED AND TURBINE SPEED < 2800 RPM STEP - 2 1. SWITCH ON AUXILIARY OIL PUMP -1 2. MONITORING TIME 2 SEC CRITERIA FOR STEP - 3 1. AOP - 1: ON OR AOP - 2 : ON OR TUR. SPEED > 2950 RPM 2. PRESSURE-OIL PRESSURE > 4.8 KG/CM

2

STEP - 3 1. SWITCH ON SLC OIL TEMPERATURE CONTROLLER 2. MONITORING TIME 20 SEC CRITERIA FOR STEP - 4 1. SLC OIL TEMPERATURE CONTROLLER ON 2. GEN. SEAL OIL GAS DP > 0.8 KG/CM 2 3. GEN SEAL OIL TURB. SIDE PRESS > 3.8 KG/CM 2 4. GEN. SEAL OIL EXCITER PRESS. > 3.8 KG/CM 2 5. HYDROGEN PURITY > 97% 6. GEN. GAS PRESS. > 3.4 KG/CM 2 7. LIQUID IN GENERATOR NOT PRESENT.

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STEP - 4 1. SWITCH SLC TURNING GEAR ON 2. MONITORING TIME 60 SEC CRITERIA FOR STEP - 5 1. GATE VALVE GEARING OPEN OR TURBINE SPEED > 250 RPM 2. SLC TURNING GEAR ON STEP-5 1. SLC AOP-1: ON 2. SLC AOP-2: ON 3. SLC EOP: ON 4. SLC JOP-1: ON 5. SLC JOP-2: ON 6. MONITORING TIME 200 SEC CRITERIA FOR STEP - 6 1. SLC AOP-1: ON 2. SLC AOP-2: ON 3. SLC EOP: ON 4. SLC JOP-1: ON 5. SLC JOP-2: ON 6. TURBINE SPEED > 15 RPM STEP - 6 1. NO COMMAND ISSUED. 2. MONITORING TIME BLOCKED CRITERIA FOR STEP - 7 1. TURBINE SPEED > 540 RPM STEP - 7 1. NO COMMAND ISSUED 2. MONITORING TIME 60 SEC

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CRITERIA FOR STEP - 8 1. JACKING OIL PUMP-1: OFF 2. JACKING OIL PUMP-2 : OFF 3. GATE VALVE GEARING CLOSED STEP - 8 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED CRITERIA FOR STEP - 9 1. TURBINE SPEED > 2950 RPM 2. PRESSURE-OIL PRESSURE > 7 KG/CM

2

STEP - 9 1. SWITCH AUXILIARY OIL PUMP (1) OFF 2. SWITCH AUXILIARY OIL PUMP (2) OFF 3. MONITORING TIME 0.5 SEC CRITERIA FOR STEP - 10 1. WAITING TIME 0.5 SEC STEP - 10 1. NO COMMAND ISSUED 2. MONITORING TIME 10 SEC CRITERIA FOR STEP - 11 1. WAITING TIME 10 SLC OR GEN LOAD > 10% 2. AUXILIARY OIL PUMP - 1 OFF 3. AUXILIARY OIL PUMP - 2 OFF 4. EMERGENCY OIL PUMP OFF STEP - 11 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED

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SUB LOOP CONTROL : OIL SYSTEM SHUTDOWN PROGRAMME CRITERIA FOR STEP: 51 1. TEMP HP CASING TOP < 100 OC 2. TEMP HP CASING BOTTOM < 100 OC STEP: 51 1. SLC TURNING GEAR: OFF 2. GATE VLV GEARING: CLOSE 3. MONITORING TIME 60 SEC CRITERIA FOR STEP: 52 1. SLC TURNING GEAR: OFF 2. GATE VLV GEARING: CLOSED STEP: 52 1. NO COMMAND ISSUED 2. MONITORING TIME: 100 SEC CRITERIA

FOR STEP: 53

1. TURBINE SPEED < 10 RPM STEP: 53 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED CRITERIA FOR STEP: 54 1. WAITING TIME 1000 SEC STEP: 54 1. SLC JOP 1 OFF 2. SLC JOP 2 OFF 3. SLC OIL TEMP CONTROL OFF 4. JOP 1 OFF 5. MONITORING 4 SEC

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CRITERIA

FOR STEP: 55

1. SLC JOP 1 OFF 2. SLC JOP 2 OFF 3. SLC OIL TEMPR CONTROL OFF 4. JOP 1 OFF 5. JOP 2 OFF STEP: 55 1. SLC AOP 1 OFF 2. SLC AOP 2 OFF 3. SLC EOP OFF 4. AOP 1 OFF 5. AOP 2 OFF 6. OIL TEMP CNTRL VLV CLOSED 7. MONITORING 30 SEC CRITERIA

FOR STEP: 56

1. SLC AOP 1 OFF 2. SLC AOP 2 OFF 3. SLC EOP OFF 4. AOP 1 OFF 5. AOP 2 OFF 6. OIL TEMP CONTRLR OFF 7. EOP OFF STEP: 56 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED

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SGC TURBINE SYSTEM LOGICS

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SUB LOOP CONTROL: TURBINE SYSTEM STARTUP OPERATION RELEASE 1. STARTING DEVICE 0% 2. POSITION SET POINT OF TURBINE CONTROL < 0% (EHC OUTPUT) 3. GENERATOR FIELD BREAKER OFF 4. GENERATOR BREAKER OFF 5. DRAIN BEFORE HP CONTROL VALVE - 1 NOT CLOSED 6. DRAIN BEFORE HP CONTROL VALVE - 2 NOT CLOSED 7. LIMIT PRESSURE OPERATION ON 8. LOAD CONTROLLER ON 9. SYNCHRONIZER OFF 10. TRIP OIL PRESSURE > 4.8 Kg/cm

2

STEP: 1 1. SWITCH ON SLC DRAINS 2. MONITORING TIME 2 SEC CRITERIA FOR STEP: 2 1. SLC DRAINS ON 2. ALL ESV S CLOSED 3. HP-CONTROL VALVE-1 CLOSED 4. HP-CONTROL VALVE-2 CLOSED 5. INTERCEPT VALVE -1 CLOSED 6. INTERCEPT VALVE-2 CLOSED 7. CRH NRV LHS CLOSED 8. CRH NRV RHS CLOSED 9. EXTRACTION

VALVE A5 < 5%

10.EXTRACTION

VALVE A4 < 5%

11.EXTRACTION

VALVE A3 < 5%

12.EXTRACTION

VALVE A2 < 5%

STEP: 2 1. NO COMMAND ISSUED 2. MONITORING TIME: 500 SEC STEP-2 COMPLETED AND IF TURBINE SPEED < 900 RPM AND SPEEDER GEAR < 100%, COMMAND IS ISSUED TO RAISE SPEEDER GEAR.

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CRITERIA FOR STEP: 3 1. TRIP FLUID PRESSURE > 5 Kg/cm

2

2. TURBINE SPEED > 15 RPM 3. CONDENSATE PUMP DISCHARGE PRESSURE: OK 4. SLC DRAINS NO FAULT 5. DT HP CASING (TOP-BOT) > MINUS 40 K 6. DT HP CASING (TOP-BOT) > PLUS 40 K 7. DT IP CASING FR (TOP-BOT) > PLUS 40 K 8. DT IP CASING FR (TOP-BOT) > MINUS 40 K 9. DT IP CASING REAR (TOP-BOT) > PLUS 40 K 10.DT IP CASING REAR (TOP-BOT) > MINUS 40 K STEP: 3 1. CLOSE DRAIN BEFORE HP CTRL VALVE -1 2. CLOSE DRAIN BEFORE HP CTRL VALVE -2 3. SWITCH SLC WARM UP CONTROLLER: OFF 4. MONITORING TIME: 60 SEC CRITERIA FOR STEP: 4 1. DRAIN BEFORE HP CTRL VLV-1: CLOSED 2. DRAIN BEFORE HP CTRL VLV-2: CLOSED 3. SLC WARM-UP CONTROLLER: OFF STEP: 4 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED CRITERIA FOR STEP: 5 1. BOILER FIRE ON 2. STEAM BEFORE HPBP-1 > 30 K SUPERHEAT 3. STEAM BEFORE HPBP-2 > 30 K SUPERHEAT 4. STEAM BEFORE LPBP-1 > 30 K SUPERHEAT 5. STEAM BEFORE LPBP-2 > 30 K SUPERHEAT 6. DT (HPBP-1 -CNTRL VALVE MID) > X 1.1 7. DT (HPBP-2 -CNTRL VALVE MID) > X 1.2

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8. TOTAL BOILER STEAM FLOW > 15% 9. DT (WET STEAM- CNTRL VALVE -1.) > X 2.1 10.DT (WET STEAM- CNTRL VALVE -2.) > X 2.2 11.DT (HPBP-1 -CNTRL VALVE MID) < X 3 12.DRN BEFORE HP ESV-1 NOT CLOSED 13.DRN BEFORE HP ESV-2 NOT CLOSED 14.DRN BEFORE INTCPT ESV-1 NOT CLOSED 15.DRN BEFORE INTCPT ESV-2 NOT CLOSED 16.OIL TEMPERATURE AFTER COOLER > 35

0

C

STEP: 5 1. STARTING DEVICE RAISE 2. MONITORING TIME 30 SEC CRITERIA FOR STEP: 6 1. ANY HP ESV OPEN STEP: 6 1. NO COMMAND ISSUED 2. MONITORING TIME 60 SEC CRITERIA FOR STEP: 7 1. HP ESV1 OPEN 2. HP ESV2 OPEN STEP-7 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED CRITERIA FOR STEP: 8 1. TOTAL STEAM FLOW >15% 2. STEAM BEFORE HP BYP 1 > 30 K SUPERHEAT 3. STEAM BEFORE HP BYP 2 > 30 K SUPERHEAT 4. STEAM BEFORE LP BYP 1 > 30 K SUPERHEAT 5. STEAM BEFORE LP BYP 2 > 30 K SUPERHEAT 6. BOILER FIRE ON

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7. DT (HP BYP1-CTRL VLV) > X 1.2 8. DT (HP BYP 2-CTRL VLV) > X 1.1 9. CONDENSER PRESSR < 0.5 kg/cm 2 STEP: 8 1. SLC WARM UP CTRL ON 2. MONITORING TIME 2 SEC CRITERIA FOR STEP: 9 1. SLC WARM UP CTRL ON STEP: 9 1. STARTING DEVICE RAISE 2. MON TIME 20 SEC CRITERIA FOR STEP: 10 1. STARTING DEVICE > 56% 2. INTCPT ESV - 1 OPEN 3. INTCPT ESV - 2 OPEN STEP: 10 1. NO COMMAND ISSUED 2. MONITORING TIME 30 SEC CRITERIA FOR STEP: 11 1. DRAINS NO FAULT 2. SPEEDER GEAR 100% 3. GLAND STEAM PESSR CONTRLR ON 4. SLC OIL TEMPR CTRL ON 5. ANY OIL VAPOUR EXTRACTOR ON 6. HYDROGEN PURITY > 97% 7. GEN GAS PRESSR > 3.4 kg/cm 2 8. GEN SEAL OIL / GAS DP > 0.9 kg/cm 2 9. GEN SEAL OIL TURB SIDE PRESSURE > 3.8 kg/cm 2 10.GEN SEAL OIL EXCITER SIDE PRESSURE > 3.8 kg/cm 2 11.LEVEL IN PRE-CHAMBER – 1&2 < MAX

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12.GEN CW FLOW > 21 M3/Hr 13.GEN STATOR CW PRESSURE > 2.4 kg/cm2 14.STATOR CW INLET TEMPERATURE < 44

0

C

15.HYDROGEN COOLER CW PRESSURE > 2.5 kg/cm 2 16.LIQUID IN GEN NOT PRESENT 17.GEN STATOR WATER CONDUCTIVITY < 5



MHO/CM

STEP: 11 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED CRITERIA FOR STEP: 12 1. ALL CRITERIA FOR STEP 11 2. STEAM BEFORE HP ESV 1 SUP HEAT > X4.1 3. STEAM BEFORE HP ESV 2 SUP HEAT > X4.2 4. DT (HP ESV 1-HP CASING) > X5.1 5. DT (HP ESV 2-HP SHAFT) > X5.2 6. TURBINE SPEED > 15 RPM 7. DT (LP BYP 1-IP CASING) > 30 K 8. DT (LP BYP 2-IP CASING) > 30 K 9. STEAM BEFORE LP BYP 1 > 480

0

C

10.STEAM BEFORE LP BYP 2 > 480

0

C

11.DRAIN BEFORE HP CONTROL VLV-1 NOT CLOSED 12.DRAIN BEFORE HP CONTROL VLV-2 NOT CLOSED 13.POWER SET POINT > 10 % 14.CONDENSER PRESSURE < 0.2 Kg/cm 2 15.REL EXP CAS 1 FRONT < +8 mm 16.REL EXP CAS 1 REAR > -2 mm 17.REL EXP CAS 2 FRONT < +8 mm 18.REL EXP CAS REAR > -2 mm 19.REL EXP CAS 3 FRONT < +8 mm 20.REL EXP CAS 3 REAR > -2 mm

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STEP: 12 1. TURBINE SPEED SET POINT RAISE 2. MONITORING TIME 40 SEC CRITERIA FOR STEP: 13 1. SPEED SET POINT > 650 RPM STEP: 13 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED CRITERIA FOR STEP: 14 1. TURBINE SPEED > 600 RPM STEP: 14 1. TSE TEST PROGRAMME BLOCK 2. WAIT TIME 180 SEC CRITERIA FOR STEP: 15 1. WAITING TIME 180 SEC 2. DT (HP BYP-HP SHAFT TEMP) < X6 3. TURBINE STRESS MARGIN > 30 K 4. BRG VIBRN CAS1 FRONT < 35 MICRON 5. BRG VIBRN CAS1 REAR < 35 MICRON 6. BRG VIBRN CAS2 FRONT < 35 MICRON 7. BRG VIBRN CAS2 REAR < 35 MICRON 8. GEN BRG VIBRN FRONT < 50 MICRON 9. BRG VIBRN GEN FRONT < 50 MICRON 10.BRG VIBRN GEN REAR < 50 MICRON 11.BRG VIBRN GEN REAR < 50 MICRON 12.BRG VIBRN HP SHAFT FRONT < MAX 13.BRG VIBRN HP SHAFT REAR < MAX 14.BRG VIBRN IP SHAFT < MAX 15.BRG VIBRN LP SHAFT < MAX

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16.RAD 16. RAD BRG1 CAS FRONT LH TOP TEMP < MAX 17.RAD 17. RAD BRG1 CAS FRONT RH TOP TEMP < MAX 18.RAD 18. RAD BRG1 CAS FRONT LH BOT TEMP < MAX 19.RAD 19. RAD BRG1 CAS FRONT RH BOT TEMP < MAX 20.RAD 20. RAD BRG1CAS REAR LH TOP TEMP < MAX 21.RAD 21. RAD BRG 1CAS REAR RH TOP TEMP < MAX 22.RAD 22. RAD BRG1 CAS REAR LH TOP TEMP < MAX 23.RAD 23. RAD BRG1 CAS REAR RH BOTTOM TEMP < MAX 24. AX AX BRG1 CAS R/F LH TEMP < MAX 25. AX AX BRG1 CAS R/F RH TEMP < MAX 26. AX AX BRG1 CAS R/R LH TEMP < MAX 27. AX AX BRG1 CAS R/R RH TEMP < MAX 28.RAD 28. RAD BRG2 CAS REAR TEMP < MAX 29.RAD 29. RAD BRG2 CAS REAR R/R RHB TEMP < MAX 30.RAD 30. RAD BRG2 CAS REAR R/F RHB TMP < MAX 31.RAD 31. RAD BRG3 CAS REAR R/R RHB TEMP < MAX 32.REL 32. REL EXP < MAX 33.GEN 33. GEN FRONT BRG TEMP < 90

0

34.GEN 34. GEN REAR BRG TEMP < 90

C

0

C

STEP: 15 1. SLC WARM UP CONTROLLER OFF 2. MONITORING TIME 2 SEC CRITERIA FOR STEP: 16 1. SLC WARM UP CONTROLLER OFF STEP: 16 1. TURB SPEED SET POINT: RAISE 2. DRN BEF HP CONTROLL VLV-1: CLOSE 3. DRN BEF HP CONTROLL VLV-2: CLOSE 4. MON TIME 200 SEC

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CRITERIA FOR STEP: 17 1. SPEED SET POINT > 3036 RPM. STEP: 17 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED CRITERIA FOR STEP: 18 1. TURBINE SPEED > 2950 RPM 2. BEAR VIB CAS GEN < MAX 3. SHAFT VIB < MAX 4. BEARING TEMP. < MAX STEP: 18 1. DRAIN BEFORE HP CTRL VLV-1: CLOSE 2. DRAIN BEFORE HP CTRL VLV-2: CLOSE 3. MONITORING TIME 40 SEC CRITERIA FOR STEP: 19 1. DRAIN BEFORE HP CTRL VLV-1: CLOSED 2. DRAIN BEFORE HP CTRL VLV-2: CLOSED STEP: 19 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED CRITERIA FOR STEP: 20 1. BOTH AOPS : OFF 2. DT (LP BYPASS 1 – IP SHAFT) < X7 3. GEN CONDITIONS FULFILLED 4. FIELD FLASH SUPPLY ON 5. AVR CONTROL SUPPLY ON 6. AVR PROT. SUPPLY ON STEP: 20 1. GEN FIELD BREAKER ON 2. WAIT TIME 15 SEC

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CRITERIA FOR STEP: 21 1. WAIT TIME 15 SEC 2. GEN FIELD BREAKER ON 3. GEN VOLTAGE >15 KV STEP: 21 1. SYNCHRONISER: ON 2. MONITORING TIME 60 SEC CRITERIA FOR STEP: 22 1. GEN BREAKER ON STEP: 22 1. STARTING DEVICE RAISE 2. MONITORING TIME 100 SEC CRITERIA FOR STEP: 23 1. GEN LOAD > 10% STEP: 23 1. NO COMMAND ISSUED 2. WAIT & MONITORING TIME 2 SEC CRITERIA FOR STEP: 24 1. WAIT TIME 2 SEC STEP: 24 1. STARTING DEVICE RAISE 2. MONITORING TIME 60 SEC CRITERIA FOR STEP: 25 1. STARTING DEVICE 100% STEP: 25 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED

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SUB LOOP CONTROL : TURBINE SYSTEM SHUTDOWN PROGRAMME STEP: 51 1. SLC DRAINS ON 2. MONITORING TIME 2 SEC CRITERIA FOR STEP: 52 1. SLC DRAIN ON STEP: 52 1. POWER SET POINT LOWER 2. MONITORING TIME BLOCK CRITERIA FOR STEP: 53 1. SPEED CONTROLLER IN ACTION 2. POWER SET POINT 0% OR GEN BRKR OFF STEP: 53 1. TURBINE SPEED SET POINT LOWER 2. MONITORING TIME 60 SEC CRITERIA FOR STEP: 54 1. STEP-53

COMPLETED

OR GENERATOR

WITH

TIME

DELAY

100

SEC

BREAKER OFF

STEP: 54 1. ELEC TURB TRIP - CHANNEL 1 2. ELEC TURB TRIP - CHANNEL 2 3. SYNCHRONISER OFF 4. MONITORING TIME 2 SEC CRITERIA FOR STEP: 55 1. SYNCHRONISER OFF 2. TRIP FLUID PRESSR < 5 kg/cm2 3. GEN FIELD BRKR OFF 4. ALL ESV S CLOSED

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STEP: 55 1. STARTING DEVICE LOWER 2. DRAIN BEFORE HP CONTROL VLV-1 OPEN 3. DRAIN BEFORE HP CONTROL VLV-2 OPEN 4. SLC WARM-UP CONTROL OFF 5. MONITORING TIME 120 SEC CRITERIA

FOR STEP: 56

1. DRAIN BEFORE HP CONTROL VLV-1 OPEN 2. DRAIN BEFORE HP CONTROL VLV-2 OPEN 3. STARTING DEVICE 0% 4. DRAINS NO FAULT 5. SLC WARM-UP CONTROLLER OFF STEP: 56 1. NO COMMAND ISSUED 2. MONITORING TIME BLOCKED

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UNIT PLANNED SHUTDOWN

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BOILER SIDE SHUTDOWN OPERATIONS

ACTION

OBSERVATION& REMARKS

1.

ENSURE all oil guns

Available.

2.

REDUCE mills firing

Maintain furnace Draught.

3.

4.

WATCH and ensure Steam temperatures to be brought down by Attemperation, for the purpose of force cooling Soot-blow boiler at160 MW.

Gradual reduction parameters.

in

steam

MAINTAIN load at 160 MW until soot blowing is over.

160 MW 5.

BRING DOWN Deaerator set point to 3.5 Kg/cm

2

6.

REDUCE load to 130 MW. CUTOUT one top pulveriser

7.

REDUCE firing gradually.

8.

CUTOUT one more mill.

D/A pressure must not fall below 2

3.5 Kg/cm to prevent cavitation. If needed, support.

take

adequate

Monitor ignition considerations.

oil

energy

120 MW 9.

CLOSE ES-7.

Ensure AS-64 opens up at CRH 2

pressure less than 9 Kg/cm . 10. STOP one P.A. Fan. 11. REDUCE load to 80 MW. 12. STOP one set of ID/FD Fan. CHECK APH tripping interlock. 13. CHECK APH gates isloated from gas/air side. 80 MW 14. CHECK changeover dampers before ID Fan have opened. 15. STOP one B.F.P 16. REDUCE firing of the remaining two mills.

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Boiler airflow may be reduced to maintain only the required amount

210

of excess air, to ensure

optimum

efficiency. 17. STOP mills and the second P.A. Fan. 18. Reduce steam temperatures by attemperation and cutting out oil elevation. TURBINE STOPPED 19. PURGE boiler for 5-minutes keeping all auxiliary / secondary / fuel dampers open.

Any of the boiler protections can be tested after the turbine is tripped.

20. STOP remaining ignitor fans.

ID/FDFans,

21. ENSURE all inlet / outlet dampers, guide/regulating vane, mill cold air dampers and discharge valves and all wind box dampers are OPEN. 22. FILL boiler to maximum drum level. 23. CLOSE SH stop valves. 24. ISOLATE feed control station. 25. STOP B.F.P. 2 26. At 2 Kg/cm drum pressure OPEN drumvents/SH and RH vents and SH drains.

27. At

flue

gas

temperature

of

1400C, STOP APH and scanner fans.

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TURBINE SIDE SHUTDOWN OPERATIONS 1.

ACTION

REDUCE load reference to 160 MW.

OBSERVATION & REMARKS Monitor TSE margins and turbine bearing vibrations/temperatures etc.

Steam temperature / pressure start dropping. SET load gradient to 5 MW/min. 210 MW 2.

ENSURE HP/LP bypass operation.

3.

REDUCE load reference to 120 MW

Keep the HP/LP Bypass control on AUTO. Load must be reduced only if steam pressure drops.

160 MW 4.

ENSURE AS-62 is open. (CRH steam to Deaerator)

5.

CUT OUT HP heaters 120 MW

6.

CARRY OUT automatic turbine test.

7.

SET load reference to 50 MW.

Refer to the chapter on ATT.

80 MW 8.

ENSURE changeover of gland seal steam controller from leak off to gland steam pressure controller supply.

9.

ENSURE changeover from UAT to station supply. 50 MW

10. Ensure steam temperature is reducing.

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Maintain TSE lower margin and casing Differential temperature.

212

11. REDUCE load reference to 30 MW. 12. CUT OUT LPHs. 13. SWITCH OFF load controller.

'Speed Controller Acting' indication comes on.

30 MW 14. TRANSFER operation to speed controller. 15. REDUCE speed reference to less than actual. (CHECK 'Reverse Power Protection'). Turbine Trip ENSURE turbine ESV's and IV's closed.

Testing of any of protections can be done.

generator

Trip fluid pressure zero. CRH NRVs are closed. Extraction NRVs valves closed.

and

block

Generator/field breaker opened. 2

Control Oil Pre. 4.8 Kg/cm . 16. AOP-1 starts on auto. (Approx. at 2950 rpm). 510 RPM 17. JOP-1 starts on AUTO 210 RPM 18. Gate valve gearing opens up. 19. LOWER speed reference to "0". 20. LOWER starting device to 0%.

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21. ENSURE opening following drains:

of

the

HP casing drain. Drain after CRH NRV's Drain before/after IV's. NRV's. Drain before extraction NRV's Seal steam header drain. Drain before ESV's. 22. STOP turbine barring.

23. SHUTDOWN pumps.

all

Barring can be stopped after casing/shaft temp. have reduced below 150 oC

condensate

At Casing temp. of 100 O C 24. SHOUTDOWN oil system 25. SWITCH-OFF all SLCs. 26. SHUT-DOWN JOP only when no movement of journal in bearing is expected due to rotor cooling.

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GENERATOR SIDE SHUTDOWN OPERATIONS

ACTION

1.

REDUCE MVAR with load

2.

CHANGEOVER to station supply from UAT at 40 MW.

3.

ISOLATE hydrogen coolers after 15 to 20 minutes of generator tripping.

4.

OPEN line isolators.

5.

REDUCE excitor controller to minimum.

6.

PURGE hydrogen by filling CO2

OBSERVATION & REMARKS

purge the by fiiling dry compresed air 7.

STOP stator water pump

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EMERGENCY HANDLING

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CONDENSATE WATER SYSTEM 1. HOTWELL LEVEL LOW. FAULT ''Hotwell level low'' alarm comes on at 400 mm wcl of Hot well level.

CONSEQUENCE

ACTION

Loss of NPSH for the pump.

Open Hotwell make-up valves MC-49/48.

CEP will trip at 250 mm wcl of hot well level.

Ensure cycle makeup from surge tank MC-54 is open.

Excessive flow to D/A from Hotwell

LP bypass valves close/trip on condensate discharge pr. low protection.

CST level is adequate.

Some leakage in steam/water (feed) circuit (water-wall super heater, Economiser etc.).

If the condensate pumps trip. Cond. vacuum may start dropping as the main ejector performance deteriorates; Cycle efficiency comes down with falling vacuum.

In case two pumps are running, stop one pump immediately, after closing Hotwell level control valves sufficiently.

ACS Xmitter failure/fault.

Reduce flow to D/A or surge tank. Close MC41 or/ and MC-27.

DM make-up may be inadequate.

Ensure there is no leakage in condensate system and CBD, EBD & IBD are closed.

DM make up pump may have tripped. 2.

HOTWELL LEVEL HIGH. FAULT

Hotwell level high annunciation comes at 600 mm wcl. MC-27 may be closed. (No flow to Deaerator or surge tank). Too much DM make-up to Hotwell.

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CONSEQUENCE Vacuum will start deteriorating if level goes higher than 1600 mm wcl. Deaerator level will start coming down, if the flow from Hotwell has been stopped. Running BFPs can trip on ''D/A level very low''.

ACTION Close DM make up valves to Hotwell.

Close cycle make-up if it is open.

CHECK & ADJUST set point less than 600 mm wcl.

218

Hotwell set point too high.

Boiler can trip on ''loss of all BFPs'' protection

ACS transmitter fault.

Unit will trip due to boiler tripping.

Condenser tube leakage.

CHECK if MC-27 is not open sufficiently, OPEN and take some water to D/A or surge tank. If the need be, open The electrical bypass V/Vs of MC-27 & MC-41 (MC-28 and MC 42 respectively.

Cond. water conductivity will increase and pH value may drop. This will cause the boiler- water chemistry to deteriorate beyond permissible limits.

Condensate pumps may have tripped

If the need be, (2nd pump comes into service automatically if discharge pressure comes below 17 KSC.

CONDENSER COOLING WATER & VACUUM SYSTEM 1.

LOSS OF CIRCULATING WATER PUMP FAULT

Operation of motor protection.

Loss of lub water pump of CW pumps.

CONSEQUENCE

ACTION

Condenser Vacuum may deteriorate due to inadequate water flow.

Immediately reduce the load on the unit to 50%.

Turbine may trip on ''Vacuum low'' protection.

Immediately throttle condenser outlet valves of both condensers to maintain the CW header pressure.

2

(0.72 Kg/cm ).

Pump mechanical failure.

Condenser exhaust hood temp may increase with the increase in back pressure and cause LPT diff. exp. (+) to increase.

Ensure LP water injection valve opens to maintain ex. Hood temp below 80 deg. C

''CW pump trip'' alarm comes on DAS.

Due to reduced header pressure (CW), the other running units may experience low vacuum.

Cut in additional ejectors, if needed, to maintain vacuum at

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0.92 Kg/cm (rated).

219

Circulating water header pressure drops slightly.

Boiler firing may increase on CMC mode due to low cycle efficiency.

CW flow through the condensers Decreases.

Start the standby CW pump, immediately, if it's available.

3. CONDENSER VACUUM IS DETERIORATING, GRADUALLY. FAULT

CONSEQUENCE

Air ingress in the condenser has increased.

Turbine vacuum starts deteriorating and LPT exhaust temp rises.

Cond. surge tank level may be very low.

Hotwell level may be very high.

ACTION Immediately decrease unit load low enough to sustain vacuum.

Turbine control valves open more to meet load demand and boiler firing increases on CMC.

Take additional air ejectors in service.

Turbine may trip on ''Vacuum low'' protection and the boiler may trip on R/H protection.

Ensure hot-well CST level and gland seal steam pr. are OK and cond pumps are on. Also ensure ejector steam pr. is adequate.

Cond. pump may have tripped or MC-27/28 is closed & MC-33/34 is not open.

Low vacuum causes the cycle efficiency to decrease.

Ensure CW header pr. and condenser circulating water flows are normal.

Cond. CW pumps may have tripped.

Due to high cond back pressures, the diaphragm may get ruptured.

If any condenser is found choked carry out cond. Backwashing

Ejector steam pressure is low.

On hydraulic governing mode unit output will reduce due to Low cond. vacuums.

Ensure all cond. CW pumps, cooling tower pumps and fans are running normally.

Cond. CW temp may be higher (CT pp. may not be in service). Condenser tubes may be fouled up or even choked.

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3 . CONDENSER WATER BOX DP HIGH (ALARM) FAULT

CONSEQUENCE

Condenser tubes may be choked or badly fouled-up.

Due to inadequate chlorination, some biological growth has taken place at the cond. inlet. Condenser CW flow decreases and its differential temp increases. (DAS indication).

Condenser choking may result in bad heat transfer and reduce CW condenser flow

Consequently condenser vacuum may fall, causing low thermal efficiency.

Unit may trip on low condenser vacuum and cause low plant load factors/availability

Condenser vacuum may start falling (alarm

ACTION Find out the condenser, which is choked by seeing CW flow (low) temp. (High) or diff. from DAS or locally. Reduce load to 80 MW (approximately)

Cut-in one more main ejector and starting ejector, if required.

Charge priming ejector and close CA-1 or CA-2 air valve of the cond. to be back-washed.

2

at 0.8 Kg/cm .)

Reverse the direction of 4-way butterfly valve of the condenser. OPEN CA-1/2 that was closed and close the other one and backwash the 2nd condenser.

BOILER FEED PUMP 1. BFP RE-CIRCULATION VALVE FAILS CLOSED. FAULT BFP discharge pressure may increase.

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CONSEQUENCE Increased differential pressure across the FW regulating valve causes the BFP speed to be reduced if it is on auto.

ACTION Adjust the recirculation of the BFP such that BFP flow does not fall less than 150T/Hr.

221

'BFP'' suction flow low alarm may come at 125 T/Hr.

Insufficient feed flow through the BFP may cause churning and may lead to seizure of the pump ultimately due to prolonged operation of BFP with insufficient feed flow.

If re-circulation cannot be maintained take another BFP in service and stop the one with the problem.

BFP bearing temperature may increase due to cavitations or churning.

2. BFP LOSS OF LUB. OIL PRESSURE FAULT Lub oil pressure low alarm comes.

CONSEQUENCE Any feed pump; trip ping out of service may cause serious drum level disturbances.

Lub oil pres sure Lo-Lo alarm comes

Boiler may trip on drum level protection.

BFP trips & brings on alarm of BFP trip.

Bearing starvation and damage may take place.

Filters may be chocked up

Drum level will drop momentarily and Deaerator may increase slightly

BFP's lub oil Pressure switch may have malfunctioned.

Other running BFP goes fully loaded

("lub. oil pr. adequate" lamp remains on).

The standby BFP gets an auto start command & comes into service after 5 sec. time delay

ACTION Ensure immediately that standby BFP is available.

Maintain level otherwise, unit may trip on 'Low' drum level protection.

Unit may run back on CMC mode. Avoid any possible failure by cutting in oil elevation

If the standby BFP has not started, then start it manually. Instruct local operator to change over the oil filters (duplex).

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3. BFP BEARING VIBRATION: HIGH FAULT

CONSEQUENCE

Lub oil quality bad.

BFP may trip at high (7 mm/sec.) vibration level.

Damaged bearing. Mechanical problems in pump Cavitation due to air/vapour ingress into BFP.

Boiler may trip if no other BFP is in operation Boiler may also trip on drum level fluctuations (V.HI / V.LO).

Unit may trip or run back on CMC to its lower load limit

ACTION Unit runs back on CMC if any BFP trips and the standby pump do not come into operation within 10 sec

Avoid any possible flame failure due to unloading of the mills on CMC runback, Cutin oil elevation. Ensure the D/A pr. is not dropping rapidly after a tripping; and BFP suction pr. is adequate.

4. BFP HYDRAULIC COUPLING OUTLET OIL TEMPERATURE IS GOING HIGH. FAULT BFP may be running on low scoop tube position for a long time.

CONSEQUENCE At 130oC working oil outlet temperature, the BFP may trip and can cause drum level Fluctuations.

ACTION Instruct local operator to change over working oil coolers.

BFP working oil cooler may be fouled up.

Unit may run-back on CMC to lower load limit.

Ensure ARCW pump pr. is adequate.

BFP cooling water pr. (ARCW) may be low.

Unit may trip due to loss of all BFPs.

Increase BFP scoop tube position.

''BFP brg. metal/oil temp high''& "BFP hydraulic coupling oil temp high'' alarms may start flashing. 5. BFP SUCTION PRESSURE IS FALLING LOW. FAULT Deaerator pressure

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CONSEQUENCE BFP may trip on low

ACTION Ensure standby BFP is

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may be falling.

suction pressure. (< 6.5 2

Kg/cm ) BFP suction strainer chokes.

Boiler/unit may trip or run back on CMC.

''BFP suction pressure low'' and ''BFP suction strainer clogged'' alarms start flashing.

BFP may cavitate and seize ultimately.

available and comes on, in service. Maintain D/A pressure.

Shut-down the BFP for strainer cleaning and maintenance.

6. BOILER FEED PUMP MASTER SPEED CONTROLLER FAILS HIGH. FAULT BFP speed controllers go to maximum.

F.W. control valve differential pressure indicator goes to zero.

CONSEQUENCE Drum level will start increasing.

The high range feed control valve will start closing in response of high feed water flow and drum.

Feed water flow increases.

BFP may trip on account of high feed flow.

BFP flow high alarm may come.

Drum level high alarm comes if the level reaches 125 mm. Unit trip will occur if level reaches 225 mm and remains for more than 10 secs.

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ACTION Transfer the BFP master controller to manual mode. Reduce the individual speed controller’s output to bring down the Water flow, if needed. If BFP flow is more than 430 T/hr. for more than a minute, BFP will trip immediately reduce the scoop controllers

Watch the drum level & ensure it is maintained normal.

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REGENERATIVE FEED HEATING SYSTEM 1. EXTRACTION SHUT- OFF VALVE ES-6 TO HP HEATER-6 FAILS CLOSED FAULT Extraction shut- off valve es-6 to hp heater6 fails closed

CONSEQUENCE

ACTION

FW temperature leaving HPH-6 will be equal to FW temp out of HPH-5.

Give ES-6 an opening command.

Spurious electrical fault.

HP control valve position decreases slightly on increasing MW.

If it does not open reduce the boiler firing and RH outlet.

Indication/ Causes:

Drum level drops due to shrinkage.

Extraction block valve ES-6 close indication comes.

HPH-6 normal drain valve goes closed as soon as ES-6 closes completely.

Throttle pressure increases momentarily and then drops.

Watch the steam temperature at SH outlet and RH outlet Check the steam temperature before attemperation. If it is increasing, then increase the attemperation slowly to control the main steam/ reheat temperature

Firing rate increases if unit is on CMC and slight loss of efficiency caused by loss of a feed water heater.

Normal drain to HPH-5 goes closed. Drum level drops.

2. LP HEATER-3: TUBE LEAK. FAULT

CONSEQUENCE Extraction steam line NRVs to Heater-3 will close down.

Possible Causes:

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Extraction line drain valve on turbine panel opens when NRV is less

ACTION Drain the affected heater and try to charge the heater If level does not come down, try to bypass the heater.

225

Tube rupture

Condensate flow to Deaerator drops by 100 T/hr.

LP Heater-3 level high alarm comes.

Deaerator level controller output increases on decreasing D/A level

LPH-3 alternate drain valve begins to open.

Deaerator level controller output increases on decreasing Deaerator level.

LPH-3 normal drain valve closes.

Condensate discharge header pr. decreases since condensate is re-circulating through LPH-3.

Check the proper closure of extraction block valve and NR valves. Instruct the local operator to bypass the heater from feed waterside. Maintain the Deaerator level and condensate pump discharge pressure. Take Hotwell level control in manual and reduce its output to maintain the condensate pump discharge pressure.

LPH-3 level Hi-Hi alarm comes in DAS LP heater extraction steam block valve ES-3

If condensate discharge header pressure drops 2 below 17.5 Kg/cm for 15 secs., condensate pump will trip.

LPH-3 extraction line drain valve DW-80 opens. Feed water temp. to deaerator will decrease.

3. HP HEATER TUBE LEAK. FAULT HPH-6 level high alarm comes.

CONSEQUENCE Extraction steam line NR valves to Heater-6 will close down.

HPH-6 alternate drain valve to condenser opens. Red light comes on.

Extraction line drain valves on turbine panel open when NRV is less than 5% open.

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ACTION Under very high level HP heaters get bypassed on waterside and extraction valve closes. However, it is advised not to wait for this action.

226

HPH-6 level high and hi-hi alarm comes in DAS.

HPH-6 & HPH-5 heater extraction drain valves ES-6 and ES-5 set closed.

Extraction steam line drains DW-75 and DW74 open. HPH-6 normal drain valves HD-37 and HD51 to HPH-5 and deaerator closes.

Feed water temperature leaving HPH-6 drops down.

Bypass the heaters by energising the group bypass valves

Drum pressure will increase due to closure of extraction valve.

Flue gas temperature leaving furnace will increase.

Tilt the burner tilts to negative side to prevent the shooting up of R/H temperature. Watch the drum level. Take it on manual if necessary

Main steam temperature leaving furnace will increase.

NOTE: one can maintain full load without HP Heater also

Drum level drops due to shrinkage.

Check the heater level from the local.

Throttle pressure drops as the efficiency drops.

4. HPH-6 ALTERNATE DRAIN VALVE FAILS OPEN. FAULT Spurious control signal.

CONSEQUENCE When all the condensate has got drained out of the FW heater, steam will start blowing directly through the heater and into the condenser.

ACTION Restore instrument air pressure if possible.

Instrument air failure.

Reset and put on Remote, if needed; the pneumatic control valves, after air supply is restored.

HPH-6 alternate drain valve HD- 43 open indication comes HPH-6 normal drain to HPH-5 closes.

If required, get the alternate drain closed manually.

If there is water in the heater

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Ensure HPH level is

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due to higher surface area, the FW temperature should increase slightly.

maintained normal.

If the heater is drained completely, then the FW temperature will drop, as latent heat of steam is not being utilised for feed water heating. Boiler heat rate goes up and fuel firing has to increase to maintain steam parameters.

AIR PRE-HEATER 1. AIR PRE HEATER BEARING TEMPERATURE VERY HIGH. FAULT

CONSEQUENCE

Cooler may be fouled up.

At high bearing temp 100 oC the APH can trip.

Lub. oil pump may have tripped on coupling failure

Due to interlock if APH trips corresponding ID/FD Fan will also trip.

Inadequate cooling water flow.

Unit load comes down to approx. 50% on CMC.

Alarm comes on at 75oC.

Furnace/flame gets disturbed, depending on flame configuration. Boiler may trip on loss of flame or furnace pressure high or low.

ACTION Normalise cooling water pressure and flow. If lub. oil pump is found tripped start the standby pump. Restart the APH, ID and FD fan and raise the unit load. Note: Starting of 2nd guide brg. pump automatically brings in the second oil cooler into service provided it's charged from the water side.

2.A. AIR PRE-HEATER ELECTRIC MOTOR TRIPPED. FAULT ''APH electrical motor trip'' alarm comes on in UCB.

The bearing temperature KORBA SIMULATOR

CONSEQUENCE

ACTION

Corresponding ID/FD Fans will trip if the air motor does not come on interlock.

Ensure the air motor comes into service.

Due to inadequate

If possible restore 228

very high protection may have acted.

excess air in boiler (fuel rich mixture) flame out may occur and boiler can trip.

electrical supply and start the APH immediately.

Motor/breaker protection may have acted.

Fuel rich mixtures may cause boiler explosion and result in damages to boiler supports.

Ensure sevice air pr. is adequate and air motor isolating valves are open.

Electrical supply may have failed.

Unit runs back on CMC mode due to ID/FD fans tripping.

If air motor is not available, cut in oil elev. & reduce boiler firing to approx (50%) and transfer load of the corresponding ID/FD Fans on the other pair completely.

2.B. APH ELECTRIC DRIVE TRIPPED AND AIR MOTOR FAILS TO START. FAULT

CONSEQUENCE

ACTION

Air motor may not be lined up.

With a time delay of 30 secs. tripped APH's isolating dampers are closed and corresponding ID/FD fans also trip-out.

Ensure service air pr. is adequate and the isolating valves of the air motor are open.

Service air pressure

Unit runs back on CMC.

If air motor is not available, immediately transfer load of ID/FD fans to the other pair or start afresh the 2nd pair of ID/FD FANS & maintain draft & airflow in boiler.

Boiler may trip due to furnace disturbances or flame failure.

Reduce boiler firing immediately.

2

< 5 Kg/cm .

Solenoid may be faulty.

3. AIR PRE-HEATER ON FIRE. FAULT Oil deposition on air pre-heater element. KORBA SIMULATOR

CONSEQUENCE Overall damage to the air pre-heater element and

ACTION Unload and stop corresponding ID/ FD 229

parts. High flue gas temperature

''APH fire detection temperature trouble'' alarm comes in the UCB.

Fans quickly.

Loss of generation due to unavailability of one set of APH/ID/ FD Fans.

Stop air heater and ensure isolation dampers are closed.

Lower cycle efficiency due to part load operation.

Wait until all temperatures become normal. Then start air heater electrical motor again

Flue gas temp. before /after air heater and secondary air temp. increases.

APH soot blowing must be done regularly in each shift& positively after every boiler light up.

Note : Any APH may be allowed to run on air motor (or air motor bypass mode) provided the gas inlet temperature of the APH is maintained within 370 oC (max.)

INDUCED DRAUGHT FAN 1. ID FAN LUB. OIL PRESSURE / BEARING TEMPERATURE TROUBLE. FAULT Lub. oil may be inadequate.

CONSEQUENCE ID Fan may trip on tank level by lub. oil pump pressure or very high bearing temperature.

ACTION Ensure the stand- very low lub. oil pump is taken into service.

Lub. oil filters may be choked.

Unit runs back on CMC to low load limit. (Approx. 50%).

Greasing long overdue in fan bearings.

Corresponding FD Fan can also trip due to ID fan tripping.

Reduce load on the troubled ID Fan and also on the unit, if furnace is geting pressurised.

Undesirable furnace pressurisation.

Stablise furnace.

Boiler/unit may trip due to ''all IDs tripping'' or ''all FDs tripping''.

Cut-in oil as quickly as possible to avoid flame failure trip.

Corresponding alarm will indicate the problem area.

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Top-up oil level in the lub. oil tank. Clean the filters.

230

Boiler/unit may trip due to ''all IDs tripping'' or ''all FDs tripping''.

If available, get ID Fan bearing greased up and Gradually increase loading, on the fan. If unavoidable, shutdown the ID Fan. The other fan set must be running before shutting down any ID Fan.

2. ID FAN TRIP. FAULT

CONSEQUENCE

ACTION

Motor over-loaded.

Corresponding FD Fan shall trip.

Immediately cut in suitable oil elevations.

Corresponding FD Fan has tripped.

Unit runs back on CMC to 50% load.

Reduce boiler firing from the upper elevations to make it compatible with available airflow; to avoid fuel rich furnace.

Spurious electrical fault.

Furnace pressure increases (above atmospheric).

Lub. Oil pressure problem.

The other ID/FD Fan pair becomes over-loaded if on auto.

Bearing temperature problem.

May lead to partial flame failure due to fuel rich mixtures in the furnace and cause a lot of furnace disturbance.

Immediately cut in suitable oil elevations.

Reduce boiler firing from the upper elevations to make it compatible with available airflow; to avoid fuel rich furnace.

Corresponding APH may have tripped.

Reduce Unit load to approx. 50% manually

All annunciations pertaining to the causes of tripping will annunciate.

If possible, restart ID Fan and the corresponding FD Fan and stablise unit at 200 MW.

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FORCED DRAUGHT FAN 1. FD FAN TRIPPED. FAULT

CONSEQUENCE

Lub oil pressure trouble.

Unit runs back on CMC to minimum load set point.

Bearing temperature trouble. ID fan has tripped.

Load is reduced to 105 MW

FD lub. Oil pressure low. (‘‘Lub. Oil pressure low'' alarm comes in.

If load does not drop automatically, reduce the load manually to 50% to suit one fan set.

Oxygen in flue gas decreases.

Cut in oil to avoid flame failure.

Fuel flow drops down to available airflow.

Maintain O2 (3%-5%) in

Corresponding ID fan trips out.

''FD Fan trip'' alarm and white trip lamp comes on.

ACTION

Flame fluctuations. may take place.

the flue gases.

Maintain furnace draught between -5 mm wcl. to 10 mm wcl. If boiler has tripped then make preparation for light-up again.

Boiler may trip on ''all FD fans tripped''.

2. FD FAN BEARING TEMPERATURE GOING HIGH.

FAULT

CONSEQUENCE

Cooling water flow may be inadequate

Load drops down to 100 MW approx. as unit runs back on CMC to min. load set point.

Coolers may be fouled up.

Corresponding ID Fan trips.

Bearing temperature increases. Alarm comes in at 95 oC.

Unit may trip on '' All FDs tripped''.

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ACTION Reduce load on the FD Fan. INSTRUCT local operator to charge the other lub. Oil cooler.

If the other fan set is not running and available for operation, put them in to avoid a unit trip.

232

FD Fan-A trips when bearing temperature reaches 105 oC.

PRIMARY AIR FAN 1. PA FAN TRIPPED FAULT

CONSEQUENCE

ACTION

''PA Fan Trip'' annunciation comes on.

Hot primary air header pressure may dip and cause '' PA header pressure low'' alarm at 585 mm wcl.

Maintain furnace draught (-5 mm wcl to 10 mm wcl).

If the tripping is due to high bearing temp. (104 oC).

Mills start tripping from top until no more than three mills are in service.

Maintain PA header pressure at 760 mm.

Corresponding alarm comes on before tripping of the fan (85oC).

Spurious electrical tripping.

Boiler has tripped.

Lub. Oil pressure may be very low.

If the 2nd fan is running and control is on auto, 2nd fan takes up load and bring up the PA header pressure to normal (760 mm).

Check the bearing temperature indcations locally and in UCB, for the fan.

Discharge damper of tripped fan closes and regulating vanes comes to minimum position. Turbine load comes down up to approx. 50% on CMC.

Check the running mills for possible choking.

Unit runs back on CMC. If not on CMC, reduce load on turbine up to 40%-50% manually. CHECK the lub. Oil pump system. If possible, RESTART and load the PA Fan

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and stablise unit at 200 MW.

2. PA FAN VIBRATION TROUBLE FAULT

CONSEQUENCE

''PA Fan vibration high'' annunciation comes on (1.5 mm/sec)

High vibration can damage the bearing and shaft of the fan

Damaged bearing.

At 2.5 mm /sec pk., PA fan is recommended to be tripped. Pulverisers in excess of 3, may have to be stopped and unit load may have to be lowered.

Loose bearing pedestal bolts.

Reduced boiler efficiency at part load.

Quality of lub oil may have deteriorated.

Machine down time increases the maintenance overhead.

ACTION Reduce loading in the fan immediately, load the other fan if that's running or take the second fan into service.

Instruct the local operator to check up the bearings, lub. oil pressure, bearing temp and vibration etc.

If required (on account of high vibration) stop the fan immediately. (Follow shutdown procedures).

3. PA FAN LUB. OIL TROUBLE FAULT Corresponding facia/window glows on.

Lub. oil pressure may be lower than 1.6 Kg/cm2.

Filters may be choked.

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CONSEQUENCE

ACTION

It can starve the bearing of oil, brg. Temperature can go high. It can even damage the bearing.

Check if lub. oil pump is running and pressure adequate(2.5 g/cm2.)

Fan trips if lub. oil pressure Lo-Lo alarm

CHECK if the other pump comes on interlock, at 1.6 kg/cm2. if pressure keeps falling.

comes on at 1.2 Kg/cm 2.

Pulverisers in excess of 3 will trip and the boiler load reduces.

Changeover the lub. oil filters to maintain lub. oil pressure.

234

Pump glands may be leaking.

COAL PULVERISER SYSTEM 1. PULVERISER DP GOES HIGH. FAULT ''Pulveriser DP high'' alarm comes at 240 mm wcl. mill DP.

Coal pulveriser may be Choking up.

CONSEQUENCE The pulveriser may be choked up completely. This may damage the dust guard or the motor or the mill coupling because of overloading. Boiler steam pressure/temp may come down. Turbine load comes down.

Pulveriser motor gets overloaded. Pulveriser out-let temperature falls low.

ACTION Maintain pulveriser outlet temperature at 75 0C.

(if needed, take control on manual). Cut in another mill Raise load on T/G.

Reduce feeding. See if DP improves. Choking reduces the mill output.

Too much coal feeding.

At high DP (240 mm) or mill current (38 amp.), feeder speed runs back to minimum.

Reject mouth choked up because of some foreign material stuck up in reject sprout (not simulated).

Oxygen (%) goes high due to reduced coal input to furnace.

Also check up locally the condition of reject mouth whether it is choked up and air is coming. NOTE: If pulveriser is completely choked up, STOP feeder, STOP mill. Issue, work permit to BMD (Boiler Maintenance Division).

Moisture content of the coal may be high.

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2. COAL FEEDER TRIPPED. FAULT Motor may be overloaded.

CONSEQUENCE Feeder tripping will stop the coal flow to the mill. Hot air damper closes after a time delay of 30 secs.

ACTION After feeder tripping check if hot air damper & gate have closed & cold air opened 100%.

Silo gate closed. No coal flow to the pulveriser for more than 10 secs.

Mill current goes no load amps Boiler/ unit load also comes down. Change fuse if needed.

Check the healthiness of feeder's electrical supply.

Adjacent mill will trip (if it's feeder is not established) due to loss of ignition energy.

Transfer fuel master to manual control & prevent the overloading of other running coal feeders. Take the other available pulveriser in service and raise load.

3. PULVERISER TRIPPED FAULT

CONSEQUENCE

Ignition energy may have been lost.

If the adjacent mill feeder is not established, that mill trips out.

PA header pressure may be low (585 mm wcl).

Boiler/unit load may come down.

Anyone PA fan trips.

ACTION Restore ignition support and cut-in the tripped adjacent mill.

Stabilise furnace draft and bring down the O 2% to 4% - 5%.

Oxygen percentage will start increasing.

Cut in oil guns and transfer fuel master to manual, if found necessary.

Boiler may trip due to furnace/flame disturbances.

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4. MILL OUTLET TEMPERATURE GOING HIGH. FAULT Mill discharge temperature high alarm comes on at 95 0C. Change in coal quality(volatile matter).

Pulveriser fire due to lean (explosive) air coal mixtures in the mill.

CONSEQUENCE

ACTION

At 95 0C mill cold air damper opens 100% and hot air damper and gate close fully. Mill temp. starts coming down, increasing the possibility of mill choking if coal feeding is not reduced immediately Prolonged operation of the mill with high outlet temp increases the possibility of explosion.

Ask local operator to remove all men working near/on the mill. Ensure HAG/HAD of the mill are closed and CAD is opened

Cutting all air supply and coal over feeding can smother small fires. Ensure continuous coal supply for the mill.

Temperature controller may have failed.

Mill fire may spread to other parts of the mill piping.

Cold air damper may be jammed-up.

If needed, transfer the mill air control to manual & maintain temp. /flow.

5. MILL CURRENT HIGH (MORE THAN 38 AMP.) FAULT

CONSEQUENCE

Grindability index low.

Pulveriser capacity reduced due to the classifier setting too high.

Pulveriser may be choking up.

KORBA SIMULATOR

Mill requires more power for the same output. At motor load of 38 Amp. Feeder speed runs back to minimum (30%) rated). Unit load comes down.

ACTION Reduce feeder speed to prevent motor overloading. Put another pulveriser in service to maintain unit load.

Maintain PA header pressure at 760 mm wcl to avoid coal hang-up in mill.

237

Pulveriser may not have been cleared for a long time.

Discharge temperature of the mill tends to increase back.

Instruct local operator to operate the reject gate to evacuate the mill.

At 95 O C hot air damper closes. HAG also closes after a time delay.

Instruct shift chemist to check for coal fineness and re-adjust the classifier setting.

Mill may trip on over load and other running feeders will overload, if on auto

6. COAL FLOW TO MILL INDICATION GOES OFF. FAULT

CONSEQUENCE

Feeder belt may be broken and feeder coal flow is lost. Feeder discharge chute may get plugged.

Pulveriser discharge temp. may increase. Pulveriser DP reduces. HAD & HAG close at 95 0C and CAD goes to 100 % opening Mill motor current comes down due to gradual loss of coal, as mill inlet chute is getting plugged.

Feeder coal flow transmitter may be faulty.

ACTION Maintain furnace draft and oxygen percentage. Take associated oil guns in service to stabilise furnace. Stop the mill after it gets emptied.

HAD & HAG close at 95 0C. as mill outlet temp goes up with loss of coal to mill.

Take associated oil guns in service to stabilise furnace draught.

Feeder trips on overload, as the coal chute is completely plugged.

Adjust fuel master to maintain loads on the running feeders (auto).

Other feeders start loading up, if on auto.

If other mill is available, cut-in the mill and raise unit load. Look for reasons for the too much moisture in coal.

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7. FUEL FLOW RUN BACK TO LESS THAN DEMAND (DROPS BY 20%). FAULT

CONSEQUENCE

ACTION

Spurious electrical malfunction.

All feeders get unloaded by 20% (Combustion control is on Auto).

Raise fuel master output to increase load.

Combustion control trips to manual.

Airflow reduces by 20%.

Continue operation on 'Manual' mode.

''ACS auto to manual transfer’’ alarm comes in.

Drum level drops due to shrinking.

Maintain mill parameters.

Boiler pressure also drops.

Maintain boiler parameters.

Unit load decreases.

Maintain unit load at 100% MCR.

If no action taken, load steadies down at 80% of rate value (approx.).

If required, take the other available mill in service.

8. PULVERISER HOT AIR GATE FAILS CLOSED. FAULT Spurious electrical signal causes the HAG to close.

CONSEQUENCE Pulveriser cold air damper goes 100% open. HAD goes closed.

Someone may have closed hot air gate locally.

ACTION Cut in corresponding oil elevation to stabilise flame. Reduce coal feeder loading to avoid mill choking due to low temperature operation.

Pulveriser temperature starts dropping.

Instruct local operator to open the hot air gate locally or inform C&I maintenance.

Pulveriser current runs up if feeder speed is not reduced (Because of poorer grindability of high moisture coal).

If unavoidable, stop the pulveriser and cut-in a new mill.

Pulveriser DP may go low due

Stabilise unit load at

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239

to reduced air volume if CAD is not opened.

200 MW.

NOTE: All pneumatically operated dampers must be reset and put on remote operation, only after ensuring E/P converter and the actual damper position are matching.

9. PULVERISER AIRFLOW FEED BACK OFF SET 25% HIGH AIRFLOW READING) FAULT

CONSEQUENCE

Flow measuring pitot tube may be plugged.

UCB instrument for airflow indicator may be faulty.

Mill air control, if on auto reduces the actual mill airflow and airflow reading drops a little.

10.

HAD and CAD close partially to compensate for increased airflow feed back signal.

ACTION Reduce feeder speed slightly to maintain pulveriser DP.

Mill DP increase as the coal retention in the mill goes up due to decreased airflow; hence mill DP goes up along with pulveriser current.

Take mill air control on manual and adjust the airflow to the required 60 T/Hr.

Pulveriser output comes down and reject rate goes up.

Instruct local operator to evacuate mill reject locally.

Boiler/unit load comes down and oxygen percent increases

If possible, load up other mills to maintain unit load.

Pulveriser PA flow Temperature Compensation Thermo-Couple Fails.

FAULT

CONSEQUENCE

Thermocouple wire broken.

Hot Primary Air temperature indication goes up to 400 deg. C. (falsely) on DAS and ''Hot PA

KORBA SIMULATOR

Airflow indication comes down but actual airflow remains as it was initially. HAD/CAD modulate to restore airflow; thus raising the actual airflow through mill.

ACTION Reduce feeder speed to contain mill DP.

If feeder runs back, due to high mill DP; let mill get emptied and stabilise mill.

240

to mill temp. HI'' alarm comes on DAS. Mill DP goes up due to excessive airflow.

Transfer mill air control to manual to control mill Airflow and temperature.

11. COAL FEEDER FLOW INDICATION LOST. FAULT Belt broken.

Transmitters failure (In this case, feeder trips to manual from auto) and ' ACS to manual' annunciation flashes.

CONSEQUENCE

ACTION

If belt is broken coal flow to pulveriser stops after sometime and pulveriser current comes down.

Immediately take the fuel master on manual and prevent overloading of other feeders.

If pulveriser is running normal (without drop in current) that indicates flow transmitter failure, in which case other feeders overload to maintain boiler load, if on auto.

Maintain O2 % approx. 3%-4%.

If other feeders have overloaded, reduce their output gradually. A fuel rich mixture may result in furnace explosion if boiler does not trip on flame failure, on account of increased firing and insufficient airflow.

11.

If flame quality has deteriorated (as shown by scanners) and opacity has increased, immediately’ hand-trip' the pulveriser (if severe fluctuations of furnace draught are noticed) and see if things improve.

PRIMARY AIR PRESSURE CONTROLLER MALFUNCTION (P A HEADER PRESSURE DOES NOT CHANGE WHEN REQUIRED).

FAULT Fan vanes freeze. Mechanical jamming.

If more air is demanded (while taking another KORBA SIMULATOR

CONSEQUENCE At PA header pressure of 585 mm wcl. all pulveriser trip out after 5 sec.time delay.

ACTION As soon as drop in header pressure is noticed immediately trip the new mill, which is being taken in service.

Boiler will trip if no oil elevation is in service and all pulverisers trip

Ask local operator to check the freeness of guide vanes, control air 241

pulveriser), controller output goes to 100% But actually header pressure drops).

out.

At 525 mm wcl PA header pressure, all mills trip instantaneously. Pulverisers coal output reduces at reduced pressure of primary air.

supply & local switch on Remote for operation from UCB.

NOTE: E/P converter and the IGV positions must be made equal before it's put on 'Remote'; to avoid any inadvertent change in PA header pressure.

TURBINES AND AUXILIARY SYSTEM 1. TURBINE SHAFT OIL PUMP FAILURE. FAULT

CONSEQUENCE

ACTION

Broken impeller due to material defect.

High vibrations can damage the bearings of the turbine.

Immediately trip the unit manually from UCB.

Lub oil/ control oil pressure drops, AOP-1 comes on AUTO (interlock).

Continued operation of the turbine in this condition is not recommended. It may result in damage to other turbine parts. Once Trip oil Pr. is <5.0 2 Kg/cm . ESVs will CLOSE

Cut-down boiler fire immediately but gradually and shutdown

High vibration in bearing No.1.

Turbine will Trip without any fault indication

2. TURBINE LUB OIL RESERVOIR LEVEL LOW. FAULT

CONSEQUENCE

A leak in the lub oil cooler or oil line.

''MOT level low' alarm annunciation' in UCB'.

KORBA SIMULATOR

ACTION

At -900 mm. MOT level fire protection-1 operates. Turbine electrical trip is initiated.

If possible quickly, switch over the leaking cooler to the one on standby and see if MOT level improves.

Vacuum breaker opens.

If unit trips, RESET turbine fire protection and make-up lub. Oil

242

level in MOT.

''Fire protection oil tank level LOW'' alarm comes on in UCB.

LP bypass, if charged, trips on low condenser vacuum.

Proceed to revive the unit, after getting the lub oil leakage attended and MOT level topped up.

Boiler trips on R/H protection after 10 secs time delay.

3. LOSS OF TURBO SUPERVISORY POWER. Power supply to turbosupervisory cabinet failed due to blowing up of the fuse.

All turbo-supervisory parameter indications associated with the TSI will be lost, including vibration expansion and shaft position.

Get the fuse replaced. Mean while do not change any parameters.

TSI power supply failure alarm comes in

4. BROKEN LAST STAGE BLADE OF L. P. TURBINE. Turbine bearing vibrations go up, especially bearing No.4. Broken pieces from the blade may damage the condenser tubes, resulting in condenser tube leakage.

-

-

Immediately trip the turbine/unit from UCB. Prepare for shutting down the boiler by cutting out the coal firing.

5. MAIN TURBINE ELECTRO-HYDRAULIC CONTROLLER FAILS HIGH. The machine becomes overloaded unduly

KORBA SIMULATOR

Immediately start reducing the hydraulic governer to get the desired load. (When the speeder gear position gets low enough to take over from EHC, a slight decrease in secondary oil pressure to HP/IP control valves is seen.)

243

''EHC Faulted'' alarm comes on.

EHC output goes to 100%.

Turbine loads up to max limit set by hydraulic speed control.

Boiler metal temp goes up as the boiler loads up (If the unit is on CMC or boiler follow mode). Generator/generator transformer winding temperatures start going up, as generator overloads. Continued and prolonged operation may lead to tripping of T/G unit on high winding temperatures of generator or transformers due to overload.

Lowering of starting device, instead of the speeder gear, brings the load change much faster. After the desired load has been reached, speeder gear is lowered until it takes over; and then starting device is again raised to 100%

HP control valves go 100% open and the boiler firing goes up on boiler follow mode.

6. TURBINE AXIAL SHIFT HIGH. "Thrust bearing metal temp high'' alarm may come in UCB.

Unit may trip on high thrust pad wear protection (0.6 mm).

Immediately decrease load on M/C and watch if axial shift improves. Otherwise, unit trips on thrust pad wear protection. (Boiler may trip on R/H protection)

Unit load may have to be reduced, resulting in loss of generation ''Axial shift high'' alarm may appear.

Silica/ chemicals may have deposited on the KORBA SIMULATOR

Excessive axial shifts can cause rubbing of moving and stationary parts. Vacuum breaker valve opens up after tripping

If unavoidable, trip the turbine manually from 244

turbine blades.

and vacuum gets killed.

the UCB for investigations by the T/G maintenance.

7. TURBINE LUB. OIL TEMPERATURE IS GOING UP. Lub. Oil coolers may be fouled-up. ''Lub oil temperature after coolers high'' alarm at 47 0C. (UCB annunciation).

Oil viscosity comes down with increasing temperature of lub oil. That may lead to boundary lubrication and metal-to-metal contact. It may cause extensive damages to T/G bearing and high brg. Vibrations.

Take in service the standby lub oil cooler if available.

If high vibrations are observed, trip the turbine immediately. ''Turbine lub. Oil temperature high'' alarm at 47 0C. (UCB alarm)

Bearing outlet oil temp increases. Brg. outlet oil temp more than 78 oC causes accelerated

Ensure ARCW/CW water pressure is adequate.

aging of oil and so additional revenue losses for each oil change.

Bearing metal temp goes up ''Brg. temp high'' alarm comes at 90oC.

Maintain bearing outlet oil temp below 78 oC to curb aging of oil.

8. LOSS OF CONTROL POWER TO TURBINE EHC SYSTEM. Control supply may have gone off due to earth fault or blown fuse etc. and ''EHC control fault’’ alarm comes on.

EHC output goes to 100%.

KORBA SIMULATOR

HP/IP control valves go fully open and unit load goes up to max.

Start reducing the starting device till the load comes back to desired value.

Generator overloading may lead to winding temperatures increase.

Reduce speeder gear till a further decrease in load is observed. Raise the starting device to 100%.

Boiler firing may increase depending on 245

the operation mode & overload the mills. Indications on turbine control console goes off.

Furnace pressure may go very high. ID fans may get overloaded.

Close the isolating valves on secondary oil lines from EHC. Maintain unit load & ask the boiler operator to maintain the mill firing, furnace draft & drum level and steam parameters.

9. TURBINE STRESS EVALUATOR. Electrical fault.

Operator will have to go by matching individual metal temperature of turbine with available steam temperature. No indications direct) of stress limits shall be available.

Instruct the local operator to switch off the TSE influence (TSE influence off annunciation comes on).

Frequent changes in steam temperatures may cause undue stresses in turbine, as visual stress levels' indications will not be available for operator to go by.

On the turbine console housing AOP/JOP SLCs etc., press the master set point release push button to remove ''Stop ref. limiter'' lamp. Now the load or speed reference can be manipulated to maintain desired load/ speed.

''Turbine stress Cubicle fault' and 'Turbine stress effect off annunciations come on. 'Stop reference limiter' light comes on and any further increase in speed or load is stops.

On the TSE, the red lamp starts flashing.

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Maintain recommended rate of turbine load changes.

246

GENERATORS AND ELECTRICAL SYSTEM 1. STATOR COOLING WATER TUBE LEAK. Broken hose (connecting the conductors header).

Stator/Rotor wdg temp goes up. T/G unit should be tripped at 105 oC.

Immediately reduce load keeping with the H2 pressure. (Refer to generator capability curve.).

H2 pressure drops (Pressure

Generator will trip on generator ground fault relay protection

Reduce excitation keeping with the load.

2

low alarm at 2.8 Kg/cm ).

'Liquid in generator' alarm comes on after H2 pressure has dropped to 2.5 Kg/cm

2

Reduced hydrogen pr. requires part loading of the unit. Hence the overall efficiency will reduce. Generator winding temp may start going high due to inadequate DM water flow in the windings.

DC seal oil pump comes on low discharge pressure interlock with associated alarms.

Cut down firing to maintain MS pressure.

In emergency, trip the generator/unit manually.

NOTE: Stator water conductivity and H2 purity changes should be closely monitored.

2. HYDROGEN COOLER TUBE LEAKAGE.

Tube bursting

Cold gas temperature may rise. (Alarm at 47 0C).

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''Liquid in generator'' H2 gas coolers alarm appears after should be cut out some time delay. one by one to identify the leaking coolers. Isolate the leaking coolers. After sometime Generator will trip on generator ground fault relay protection.

247

H2 pressure drops.

Hydrogen leakage will require more hydrogen cylinders to be charged. Hyd. consumption increases.

Continued operation at reduced load (165 MW) with 3 gas coolers is permissible.

3. LOSS OF H2 / SEAL OIL PRESSURE. ''Generator cooling /seal oil working filters clogged'' alarm may come on.

Seal babbit liners may be damaged. So due to increased clearances more seal oil may drain.

Seal oil DP goes low. (Alarm at 0.9 2 Kg/cm )

Instruct local operator to charge more hydrogen cylinders.

H2 may leak out of

Maintain Gen. load as per generator capability curves; with falling H 2 Pr.

the system.

Rotor temperature goes up. ''Seal oil pressure low'' alarm comes at 3.6 Kg/cm 2 and reserve seal oil pump comes on interlock.

Hot gas temperature high alarm comes at 75 0 C.

Ensure rotor and gen. winding temp are within limits.

Under extreme conditions generator may have to be tripped, manually.

If DPR is found to be malfunctioning get it bypassed, locally.

4. GENERATOR HYDROGEN LEAKAGE. H2 pressure drops.

Hot gas temperature goes up (High alarm at

Reduce load immediately.

75 0C. H2 pressure (2.8 Kg/cm 2 low alarm sounds.

Rotor temperature goes up.

Instruct local operator to charge more hydrogen cylinders & maintain H2 pressure at 3.5 2

Kg/cm Seal oil pressure decreases to maintain DP. Reserve seal oil pump may come on KORBA SIMULATOR

T/G may have to be tripped due to high rotor winding 248

interlock.

temp at 105 0C. Hydrogen consumption per shift increases.

Maintain generator stator and rotor winding temperatures within limits.

5. GENERATOR HYDROGEN TEMPERATURE HIGH. Hydrogen cooler surfaces may be fouled up.

Hot gas and rotor temperature rise brings in associated alarms.

Cooling water flow may be inadequate.

Unit may have to be tripped on high rotor winding temperature (105 0C.).

Check if hydrogen cooler outlet valves are fully open.

Unit's generator MVA may have to be checked and lowered.

Reduce excitation in keeping with grid voltage & the load.

Cold gas temp starts going up and brings in high alarm at 45 oC.

Reduce load as per generator capability curve.

Part load operation to the generator leads to lower cycle efficiency.

6. STATOR COOLING WATER FLOW LOW. Clogged filters.

Generator trips at 3

13 m /hr. of stator water flow.

''Generator cooling/ seal oil working filters temp plugged'' alarm comes in.

Second stator water pump takes auto start at a pr. 2

of 2.3 Kg/cm . ''Stator water flow low'' alarm comes in at 18 m 3/hr.

KORBA SIMULATOR

Generator winding temp may start increasing, due to reduced stator water flow.

Switch over stator water filters.

Unload machine to 160 MW (approx.) to keep generator winding within 85 0C. Check-up stator water system for any leakage or any problems.

249

T/G may trip due to low stator water flow at 13 m 3/hr.

MISCELLANEOUS SYSTEMS 1. LOSS OF STATION AIR PRESSURE. Leakage in the pipe

At a pressure o f 3.5 2

Kg/cm , ignitor oil/atom air pressure low alarm comes and all ignitors trip out.

Immediately increase heavy oil pr. to 12.5 Kg/cm 2.

Compressor tripping. Pressure indication in UCB starts to drop.

This may lead to oil valves tripping if corresponding oil flame scanners are flickering and possibility to boiler tripping on 'Loss of all fuel' or 'Flame Failure'.

Low service air pressure alarm comes

Attend to the fault & get the leakages, if any, rectified.

OPEN Instrument& service air interconnection valve.

2

at 6 Kg/cm .

2. LOSS OF INSTRUMENT AIR PRESSURE. Compressor tripping.

2

At 5 Kg/cm instrument air pressure the following valves will OPEN

Leakage from the flange.

Maintain drum level by scoop adjustment and do not change anything on the unit.

Pressure indication drops.

1

Low instrument air Pr. alarm at 5.5 Kg/cm2

2

KORBA SIMULATOR

Decrease load gradually to keep drum level in control and also the rate of vacuum drop.

DA overflow valve (MC84). BFP re-circulation valves.

250

3

Condenser recirculation valve (MC33).

4

HPH-6 normal drain to DA (HD-51).

5

HPH-5 alternate drain to condenser (HD-31).

6

LPH-2 alternate drain HD-14.

7

LPH-3 alternate drain HD-19

8

All auxiliary dampers.

Meanwhile make arrangements to restore instrument air pressure.

-

Feed water temperature after HPHs drop slightly and cycle efficiency decreases.

Furnace pressurises slightly.

The following valves will CLOSE

KORBA SIMULATOR

1

Hotwell level controller MC-27.

2

D/A level controller MC-41.

3

Make-up controller MC54.

4

HPH-6 normal drain to HPH-5 (HD-37).

5

HPH-6 alternate drain HD-43.

6

HPH-5 normal drain to D/A HD-34.

7

LPH-2 normal drain to HD-11.

8

LPH-3 normal drain HD-16.

Hotwell and D/A level can be maintained by operating electrical bypass valves of the corresponding controllers.

-

Get AS-90 (bypass ejectors PRDS opened. (Not simulated).

251

9

10

Ejector steam pressure controller AS-56, AS79. Steam to D/A controller AS-68. All other pneumatic actuators will remain frozen at their position. Turbine may trip on vacuum protection or boiler can trip on low drum level.

2. REHEATER TUBE LEAK OR SECONDARY SUPER HEATER TUBE LEAKAGE. Overheating of tubes.

Hot R/H or main steam pressure drops.

Immediately cut down firing and reduce pressure and unit load.

Fire side corrosion.

HP control valves open more to maintain load as per reference value.

Unit may have to be shutdown immediately for maintenance as these leakages can damage the neighbouring tubes.

Severe fluctuations in flue gas DP across platen S/H, RH, economiser etc. take place.

Furnace draught becomes unstable and goes up.

ID fans load more to maintain draught. Make-up consumption goes up. Furnace pressure goes up.

Pulveriser fires more to keep the throttle pressure up. If on auto, flue gas temperatures increase.

Boiler pressure (MS/RH) drops. Relevant alarms will annunciate.

KORBA SIMULATOR

Metal temperature in boiler goes up and steam attemperation

252

goes up. D/A level tends to drop. Neighbouring tubes may also get damaged depending upon the severity of leakage.

4. WATER WALL TUBE LEAKAGE. Corrosion.

It can damage the neighbouring tubes.

Reduce load to about 150 MW

Over heating of tubes.

Feed water flow goes up, to maintain drum level. Make-up consumption increases.

Reduce firing to keep steam temperature under control.

Indications will be

Drum level drops depending upon the severity of leakage. Throttle pressure drops.

Eventually unit has to be shut down. So make preparation for a planned shutdown.

D/A level Hotwell level drop gradually Condenser surge tank level low annunciation comes on if cycle make-up is open.

NOTE: A decrease in boiler water pH is the primary indication of any water wall tube leakage.

Boiler metal temp go up as firing increases to maintain throttle pressure which goes down due to leakage Furnace draught starts hunting.

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253

5. BOILER WATER SILICA HIGH. 'Boiler water chemistry trouble' alarm comes in.

Silica carry-over increases resulting in formation of silicates on turbine blades. Turbine efficiency comes down over a time.

Start HP dosing and open CBD. Reduce load and drum pressure, as per chemist's advice to maintain drum water silica not more than 0.5 ppm .

Dust ingress into phosphate and hydrazine dozing tank. Also during shutdowns because of SH /RH tube leakages.

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254

KORBA SIMULATOR

255

EFFICIENCY ASPECTS OF POWER PLANTS

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256

KORBA SIMULATOR

257

EFFICIENCY ASPECTS OF POWER PLANTS With tremendous rise in electricity demand throughout the world, need of enormous increase in sizing and installation of power plant has been felt two to three fold. This has imposed an urgency to ensure that the plant is operated and maintained as near to optimum conditions as possible. Cost of fuel (Coal, oil, gas) is rising day by day and unless proper measures are not taken to optimise the usage, operating power plants most efficiently and economically will not come true. At current Indian fuel prices, loss of one percent in efficiency will incur an additional fuel (coal) cost of over Rs. 23 millions per annum (equivalent of additional 250 Tones of coal/day). It is of paramount importance that power plant engineers get aware of causes of poor efficiency and adopt methods to control and keep check on process parameters those will be affecting the power plant efficiency. In this chapter, an attempt has been made to educate engineers so as to find the means and ways in solving numerous problems concerning efficiency efficiency losses in power station operation. The Temperature–Entropy (T-S diagram) is represented by area between the curve and the entropy figures (0-10 KJ/kgK). 0 Temperature starts from –273 C to 0 to 700 0C. The curve representing boiling water starts from 100 0C and reaches to around 3700c and in rising side entropy scale to 4-6 KJ/kgK and the lowering side represents the dry saturated steam. Sensible heat is represented between y-axis and x-axis before latent heat covers. Latent heat is represented by the rectangle between the curves traced by entropy figures. A horizontal line gives the pressure and extends upwards. The critical point occurs at the conditions (221.2 bar abs, 374.15 OC temp and 3.17cm 3/kg volume) and at the more elevated condition the steam reaches in super critical stage. The curve represents the total heat, useful heat & the rejected heat as well. An ideal Rankine Cycle incorporating reheat and regenerative feed water heating can be represented by the curve. In the ideal cycle the steam expands in the turbine and the expansion is assumed to be frictionless and adiabatic. The expansion of steam continues until some reduced pressure. Condensation at a constant temperature takes place until all latent heat had removed (rectangle covered under X line as rejected Heat). The formulae that follow can be referred for calculating the thermal efficiency. There are two ways to improve the basic Rankine efficiency. efficiency. Those are: Reduce the rejected heat component and then increase the useful heat component.

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258

The rejected heat component is dependent primarily upon the condensation temperature and this in turn is determined by the cooling water temperature.(usually is controllable a little.).The useful heat is determined largely by steam temperature. The efficiency can be improved by restricting limits of upper & lower temperature by actually resorting to Reheating. Ideal Cycle efficiency for turbine conditions at 158.6 bar/566 oC/566 oC is about 47.2 %. A combination of reheating and feed heating will give an even higher ideal efficiency. The Carnot efficiency is obtained for any substance working between the limits of temperatures and the Carnot efficiency is given by (T1-T2)/T1 in which T which T 1 is the upper absolute and T 2 is the lower absolute temperature and the heat addition & heat rejection are isothermal process and that the expansion and compression of the working substance is isentropic. Of course no such substance as portrayed in the Carnot cycle exists. However the Equivalent Carnot cycle is one, which is equivalent of a given Rankine cycle. The temperature is assumed to be constant at the average temperature at which heat is received in Rankine cycle; they give the same results. Let us take a case of a unit having different figures. TSV pressure: 240 bars TSV Temperature: 590(0C) Final feed temperature: 270( 0C) Back Pressure: 30 mbar Reheat temperature: 570( 0C) Reheat pressure:50 bars abs. The efficiency of Unit –2 converts 83% of the t he available heat into electrical output. Selected parameters and its complete T-S Diagram (Ideal Steam Cycle) Steam Parameters:

Ms Pr = 160 Bar, SH temp = 570 oC,Cond.pr = 30 mbar, RH temp = 570 oC, RH Pr. = 44 Bar

Carnot Efficiency Basic:

52.1%(with 52.1%(wit h dry/sat steam between 347 oC & 24oC) 64.8%(Between 570 oC and 24oC)

Rankine Cycles Efficiency

(Ideal): 41.4%

Rankine Cycle Efficiency with

S/H: 45.7%

Rankine Cycle efficiency with with S/H & R/H: 47.5% Rankine Cycle Efficiency (with SH, RH &Regenerative &Regenerative feed heating): 53.2%(with feed feed Water temp = 180 oC) 55.8% (with Feed water Temp. 250 oC) Thermal efficiency

KORBA SIMULATOR

=

Useful heat Total heat

259

=

Total heat - Rejected heat Total heat

=

1-

Rejected Heat Total Heat

Condensate temperature:24(297.1) temperature:24(297.1)0C/K Entropy of final feed: 2.9763 KJ/kgK Total heat at TSV: 3469.9 -doEntropy at TSV: 6.3539 -do-K Total heat at R/H inlet: 3013.0 -do Total heat at IP inlet: 3595.1 -doEntropy at IP inlet: 7.1769 -do-K Heat in final feed water: 1185.2 -doHeat added in Boiler (H1-hf):2284.7-doHeat added in R/H(H1-H2): R/H(H1-H2) : 582.1-do Total Heat added: (1) 2866.1 -doEntropy change(S2-S1):(2) change(S2-S1):(2) 4.2006 -do-K Heat rejected T.(S2-S1):(3) T.(S2-S1):( 3) 1248.0 -do Work done :(1)-(3): (4) 1618.8 -doIdeal cycle frequency :(5) :(5) (4)100/(1):56.5% Alternatively Average temp. (1)/(2): 682.5 K (6) Equivalent Carnot efficiency: (7) 56.5 % = { (6) –T } 100/ (6) Overall efficiency: 46.9% If a comparison is made between the efficiency of a basic Rankine Cycle without reheat regenerative feed heating and the one with reheat and regenerative feed heating an apparent gain in efficiency of the cycle can be noticed. It can be explained on the basis of equation for efficiency of cycle; incorporating reheating increases the total heat, input, and incorporating feed heating, reduces the amount of heat rejected, thereby increasing the cycle efficiency. In general, entire cycle efficiency of a power station depends upon the efficiency of its components i.e. boiler, turbine, generator, pumps etc., efficiency of which in turn depends on many other factors as discussed here. Cycle Efficiency (ξ ( ξ)= ξ

(S.G)

*ξ

(Tur)

* ξ (Gen.)

BOILER EFFICIENCY There are two ways of determining the boiler efficiency: i) Direct & ii) Loss method.

Direct method was standard for long time, but is little used nowadays. It is basically the straight forward of measuring the heat supplied in a given time and heat added to the steam in the boiler. By this method the efficiency of a non-reheat boiler is:

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Efficiency = {Enthalpy of (steam – feed)* steam flow} 1/Cv .(coal) *Coal quantity Per unit time Losses Method: The efficiency of a modern boiler is dependent basically upon the efficiency of combustion and the heat transfer within the boiler. The efficiency of the Boiler is therefore 100% -losses. Thus, if the losses are known, the efficiency can be derived easily. The losses in the boiler comprises of the following: 1. 2.

3. 4. 5. 6. 7.

Dry flue gas loss. Moisture loss: a. Moisture in fuel. b. Combustion of hydrogen. c. Moisture in ambient air Unburnt carbon loss: a. Carbon in bottom ash. b. Carbon in flue gas Incomplete combustion. Radiation and unaccounted losses. Ash hopper loss. Mill rejects loss.

Dry Flue Gas Loss This loss is due to residual thermal energy contained in the dry flue gas when its temperature is too low for further useful work. At this point it is exhausted to atmosphere. This loss constitutes the largest portion of boiler losses and is dependent upona. Quantity of dry combustion gases. b. Temperature rise between FD Fan inlet and gas exit temperature. c. Mean specific heat of the flue gases (Constant pressure). The amount of excess air supplied over and above the theoretical air, has the greatest bearing upon this loss as this causes both quantity and temperature of the flue to deviate. A change in excess air quantity by 5% effects + 1.0% in dry flue gas loss. Dry flue gas loss ={100/12*(CO2+CO) + C/100+(S/267)-C ash}*30.6 (T-t) K J/Kg. (In fuel) Alternatively Dry flue gas loss % = K x (T-t) (on GCV v basis) In the dry gas loss equations, the abbreviations are as under: C is %carbon/kg , CO2,CO,N2 all in % by vol. as present in dry flue gas S %/kg fuel, M is Moisture /kg fuel; H is %kg fuel; h is moisture in kg/kg air Ma is dry air for comb in kg/ kg fuel; c is carbon in refuge in kg A is ash content in kg/kg fuel. GCV v gross calorific value KJ/kg, NCVp is net calorific value KJ/kg t is F.D. air inlet temp., T is the exit air temp at A/H outlet

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261

K is constant and have values as given below. K = 0.68 for anthracite = 0.63 for bituminous = 0.70 for coke = 0.56 for fuel oil.

Optimisation of Total air supply

Optimum Co2 % at Boiler outlet

Wet Flue Gas Loss (Moisture Loss) This loss is the thermal energy in water vapour entrapped in flue gases leaving boiler. The water is in the form of superheat steam if exit gas temperature is above the dew point at the stack. The total moisture loss is due to water derived from t hree sources: i) ii) iii)

Total sum of free & inherent moisture in fuel. Products of combustion of hydrogen in coal; Moisture in atmospheric air.

Wet flue gas loss =(M + 9H)/100 [1.88 (T-25) + 2442 + 4.2(25-t)] KJ/Kg. of fuel. Sensible heat in water vapour. = Wet flue Gas Loss - (GCV - NCV) Moisture in combustion air loss = Ma*h*1.88(T-t) KJ/Kg.fuel For solid liquid fuels Ma =3.034 N 2/ (CO2 + CO ){C/100 + S/267 -C in ash} Unburnt Carbon Losses The main source of this loss is due to the carbon contained in bottom ash or entrained in fly-ash leaving boiler furnace.

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This loss is dependent upon: i) Coal fineness. ii) Burner tilt, iii) Gas velocity in the furnace, iv) Combustion quality. Unburnt carbon loss = c ash* A/100 * 33820 KJ/Kg. of fuel. Where, c ash =Carbon in ash A=mass of ash, Kg/Kg. fuel CV of carbon burnt to Co 2 KJ/Kg.= 33820 11.1.4 Incomplete Combustion Loss Loss due to incomplete combustion seldom occurs in modern high capacity PF boilers under normal operating conditions due to excess air supplied for combustion. However, this loss is calculated by the following formulae: Unburnt Gas Loss: =CO/(CO2 + CO) { (C/100) + (S/267)-Cash}23717 KJ/Kg. Where C V of burning 1 Kg. of carbon in CO to CO2 is =23717

Radiation and Ash Hopper Losses: For modern boilers, these losses can be as small as 0.25%. Additionally some unaccountable losses may occur due to additional heat loss at hoppers and sensible heat in ash. In case of wet hoppers or where sprays are used, water absorbs heat and gets vaporised and turns to superheated steam in furnace; leading to moisture losses. Radiation Losses = Log 10 B = 0.1867 - 0.4238 Log 10C. (B=Radiation and unaccounted loss & C=Specific boiler capacity in Kg/s.)

Boiler load versus % radiation loss

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263

Mill Reject Loss This loss may be kept very small if the milling plant is designed, operated and maintained correctly. It can be calculated by sample of reject for calorific value and weight of rejects. Note: Efficiency calculations done on the basis of NCVp yield higher values than GCVv. Hence, calorific values must be specified clearly. Most of these boiler losses can be kept under acceptable limits by ensuring complete combustion at minimum excess air. Control of combustion process requires regulation and distribution of fuel & air to and within the furnace using: i) Milling plant; ii) Burners; iii) Air control equipments. The other factors, which must be considered, are a. The need to cool the combustion products below the softening temperature of ash before the leaving the combustion chamber. b. The need to avoid deposition of burnt coal onto wall tubes. This can induce corrosion of tubes, ultimately involving a loss of plant availability. c. The need to avoid acid corrosion of lower temperature flue gases. (The excess air quantity and flame temperature can influence Dew point temperature). TURBINE EFFICIENCY The efficiency of turbine is dependent upon the following factors. Internal Losses Nozzle Friction: The effect of nozzle friction is to reduce the effective heat drop of steam as it passes over the nozzle. The velocity of steam is reduced as it subsequently strikes the moving blades. Because of reduction of velocity there will be some shock as steam strikes the blades because blade profile is designed so that steam glides over it (for a particular steam velocity). Blade Friction: Its effect is same as of nozzle friction. Without friction the outlet relative velocity of steam would be same as inlet but because friction cannot be avoided, velocities are reduced to 90%. As friction increases, steam expansion tends to be more ''irreversible''. Stage efficiency

=

Actual heat drop Isentropic heat drop

Disc Friction: The discs on impulse turbine shafts rotate in an atmosphere of steam. The disc surface friction causes some drag and produces eddies of steam causing loss of power. This effect is more pronounced where the steam is densest. KORBA SIMULATOR

264

Diaphragm Gland and Tip Leakage: In pressure-compounded turbine there is a pressure drop across each fixed nozzle of diaphragm. Therefore, the gap between diaphragm and shaft is a source of steam leakage, which can be minimised by providing inter-stage glands for sealing. There are balancing holes on the discs through which steam can leak and cause disturbances when it joins the steam coming from the nozzles. It is extremely important, therefore, to maintain eccentricity to minimum during start-up and loading. On impulse/reaction machines, there is pressure drop across each stage or blade; thus there is steam flow around tips of all fixed and moving blade. Seals at the tips in radial & axial directions are provided. Because of wear & tear of the seals, leakage loss can amount from 0.55% to 1.0%. Partial Admission Loss: In nozzle-governed machines in particular, and in throttle governed machines at part load conditions, steam is subjected to Throttling. Apart from that in nozzle-governed machine, steam is admitted to one or more areas of the inlet nozzle ring. The valve lifts are varied in sequence, as the turbine is loaded until at full load the valves are fully open. The moving blades alternately come in and off contact of any running arcs. In the process, they run full of steam while in contact with running arc and from eddies when they come in line with non-running arcs. This leads to windage losses. However, nozzle governed machine can be said to be more efficient than throttle governed machines, at part load. While, at full load the throttle governed machines are more efficient. The basic construction and assembly of partial arc and full arc i.e. nozzle governed and throttle governed turbines, are a lot similar with only real difference being the absence of the control stage in full arc admission turbine. This arrangement dispenses with excessive stresses in the HP turbine blades and enhances the reliability of full arc admission turbines and improves their efficiency. Upon comparing the thermal performance curves of the two types of turbines it can be noted that the throttle governed, full-arc-admission turbine has better efficiency. Although as compared to the throttle governed, the nozzle controlled partial arc admission turbine does show a lower net heat rate in the lower load range; when operated in constant pressure mode, the full arc admission turbines can also exhibit a better performance in the upper load range with only per iodic load drops; by way of both, better heat rate and energy consumption. Various degrees of hybrid operation (combination of both, constant pressure and variable pressure mode) of both types further improve the thermal performance of each at partial loads also. The variable pressure mode of operation is best suited for full arc admission turbines, whereas the partial arc admission turbine operates over the entire load range with some what a lower heat rate level. For constant pressure operation, the load changing characteristics of both types of turbines indicate a better ability of full arc admission turbines to deal with severe load transient conditions, because they exhibit smaller changes in temperatures for a given load change. Load dependent temperature changes can, however, be minimised by applying hybrid pressure mode operation or can be totally eliminated by adopting the variable pressure mode operation. KORBA SIMULATOR

265

In the overall analysis, the throttle controlled, full arc admission turbine exhibits better characteristics in all cases, with the exception of excessive heat rate in the partial load range while in the constant pressure mode of operation.

Sliding Pressure Control:

Considering a throttle governed turbine reduction of load is achieved by straightforward throttling at constant enthalpy as shown by line AB. Turbine expansion line becomes at reduced load BE, resulting in reduced available heat drop. On the other hand if control valves are left fully open and boiler pressure is reduced for maintaining full steam temperature, the turbine expansion line becomes CD resulting in increased available heat drop and reduced wetness after LPT exhaust, as a bonus. Sliding pressure control is very common at part load. In nozzle governed machines when operating at part load the control valves are wide open. Hence with increase of pressure the available energy increases and efficiency improves. Consequently sliding pressure control is not applicable to this type of machine. Exhaust Losses: The kinetic energy of steam leaves the last LP stage cannot be gainfully employed to do any useful work and hence it is a loss. Leaving loss =1/2 ( mv o2 ) Where, m = mass steam flow, v o= Absolute velocity of steam at outlet of last row of blades The loss varies with (velocity) 2 and velocity varies with backpressure change.

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Wetness Loss The wetness of steam goes on increasing towards the last stages of a turbine, at a given set of parameters. Condensation of steam causes wetness or formation of water droplets on blades, which lose some mechanical work in throwing off the drops. Apart from that severe erosion is also caused to the blade tips of last stages. Generally, 1% increase in wetness causes 1% loss in efficiency

External Losses: Shaft gland leakage.; Journal and thrust bearing; Governor and oil pump.

MONITORING TURBINE PERFORMANCE Cylinder efficiency Test By accurately measuring the temperature and pressure of steam before and after HP and LP cylinder, it is quite easy to determine the respective cylinder efficiency. The LP cylinder efficiency can't be ascertained as the steam is wet there and exact 'state point' can't be located.The cylinder efficiencies do not change appreciably with load, as ratio of blade to steam speed (u/V) remains constant with load. However, due to deteriorating cylinder efficiencies, change in turbine heat rate can be computed with the following formulae: HP Cylinder ∆(HR) = {{0.43 (H-h) ∆ (n)%}1/ Kwa} *2.36 Qr/ HRa _ 2.158 Qh/3600} Where, ∆(HR) H h ∆n % KWa Qr HRa Qh

= % change in heat rate value. = Enthalpy at TSV, KJ/Kg. (ref. data) = Enthaply at HPT exhaust, KJ/Kg. (ref. data) = % change of efficiency from designed value. = Ref. alternator output, KW = Reheater steam flow (present) Kg/hr. = Reference test heat rate, KJ,/KWH = Present steam flow to HP cylinder, Kg/hr.

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IP Cylinder ∆(HR) = ∆n % { 0.928 (H1-H2)* Qr) *1/ KWa *3600 -1} Common causes of cylinder efficiency deterioration include: Damage to blades caused by debris past the strainers. Damaged seals and glands. Deposition on blades. Increased roughness of blade surfaces. The surface roughness affects the HP cylinder maximum, then IP cylinder and then comes LP cylinder. Larger machines are affected to a lesser extent as compared to smaller machines. Turbine Pressure Survey This is a very useful tool indicating the internal condition of turbine. Following steps are followed for preparing the pressure survey diagram i) Choose a pressure scale on Y-axis from zero to any pressure above ESV pressure, say, at rated load. ii) From acceptance test results or design reference, mark off various pressures at various points of tapping as shown below. iii) Join all points with a straight line.

Basic Pressure survey diagrams & effect of Heaters out of service :2 If at some later date, the pressures are noted at each point while the load is the same as plotted, as before, the points will lie on the same line if the cylinder condition has not deteriorated. But, if the load is lower and the condition of machine is same the points will plot on a line lower than the previous. When plotted pressure points are on the optimum pressure line for a particulars load it is indicative of general wear of

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diaphragm, seals etc. If the line has 'kink', then it indicates some restriction in the turbine. The pressure before the restriction will be higher, after that lower than optimum. LP cylinders are difficult to assess on pressure survey scale, as pressures can't be plotted accurately. Nevertheless, chances of rubbing and wearing are less due to liberal clearances, but there remains a possibility of silica deposits. Hence, LP inlet and bled steam pressure should be checked regularly.

Effects of Internal Restrictions

Effects of load changes

Silica can enter the system through reheater leaks during shutdown because of vacuum built up in the steam space as steam condenses. This can happen especially when vents are not opened prior to pressure decay. Also BFP and feed heaters when they are opened for maintenance, silica can enter the system. EFFECT OF OPERATING PARAMETERS ON CYCLE EFFICIENCY The complexity of a power station unit offers scope for many parameters to have deviation from optimum. Fortunately technical expertise and know-how gathered over the years facilitate ascertaining the causes of efficiency loss due to deviation from optimum, by monitoring just a few terminal conditions. They are a. b.

Turbine backpressure. ESV steam pressure.

c.

ESV/RH steam temperature.

d.

Amount of attemperation spray.

e.

Final feed water temperature.

f.

Boiler excess air.

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g.

Combustibles in ash.

h.

APH gas outlet temperature.

i.

DM water make up rate.

j. k.

Auxiliary power. Unit load.

Turbine Back Pressure This is the most important parameter that severely affects efficiency of a power plant cycle. It is dependent upon 1. Condenser air tightness. 2. CW inlet temperatures. 3. Condenser tube fouling. 4. Effect of variations of heat transferred. 5. CW flows in condenser. Generally speaking, improving the backpressure improves the amount of work done by steam, but up to a limit. Because, with increase in certain losses also increases.

Backpressure correction curves

Minimum Back press.at different loads

They can be listed as follows: 1.

CW pumping power.

2.

Leaving/exhaust loss.

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3.

Reduced condensate/feed water temperature.

4. Wetness losses. The losses mentioned will eventually significantly affect the results. Continued operation with reducing backpressure will result in net improvement in heat consumption becoming progressively less until a point is reached where gains equal the losses. There is no point for further reducing back pressure beyond this. Loss due to high CW inlet temperature may be due to inefficient cooling tower operation; can be compensated by increasing flow of CW. But the gain in efficiency must be weighted against loss due to increased CW pumping power. Loss due to incorrect CW flow can be eliminated. If the temperature rise across the condenser is less, that means more than optimum CW flow. It can be reduced. Excessive CW flow can cause under cooling of the condensate, ultimately lowering the final condensate temperature. Loss due to air ingress is entirely preventable and steps must be taken to ascertain air tightness and points of leakages, if any. Remember, 1 mm. thick air sheet has the same resistance as 17 mm. copper slab. Deviations in backpressure due to fouling cannot be eliminated thoroughly during operation. Off load cleaning of tubes is a must. However, if any increase in frequency of back washing is noted, it should be ensured that chlorination is adequate. ESV Steam Pressure On a throttle governed machine the output is proportional to 'after control valve' pressure or first stage pressure. It can be assumed that even if throttle control valves are 100% open, there is a drop of 5% - 10% in ESV pressure at control valves. Variation of turbine steam pressure causes a.

b. c.

The total heat drop to vary, higher pressure causes increased heat drops (at the same inlet temperature conditions). Increasing exhaust wetness at higher pressures. Increased turbine output for a given control valve opening such that 10% increase of pressure will produce 10% extra output.

For more common reheat type machine, variation of ACV (after control/throttle valve) pressures are proportionally dependent on load conditions, such that 50% reduction of load will reduce ATV pressure by 50% as shown in the figure. Ignoring pressure drops in reheat lines at 100% expansion lines in HP and IP/LP turbine is AB and CD respectively as shown in the figure. At. 50% output turbine expansion is EF and GH as shown.

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It can be seen that •

HPT enthalpy drop remains same.

•

IPT/LPT enthalpy drop becomes smaller in spite of increased IP inlet specific enthalpy because of reduced slope of temperature lines with respect to consistent slope of condenser pressure line.

Controlling load by sliding pressure operation on the CE boilers supplied by BHEL to NTPC within a + 10% of the rated value may yield some benefit by way of reduced throttling losses at part load.

This may also have the following disadvantages: a. Boiler pressure is reduced hence cycle efficiency is very much lower than optimum at full load conditions. b. At very low pressure, at higher loads steam volume is more, which tends to envelop water in the boiler tubes, leading to film boiling and subsequently overheating of tubes. Any deviation in turbine inlet pressure can change the steam flow through turbine, because of which stage pressure and extraction pressure will change, changing feed water temperature. The volumetric flow to condenser also changes accordingly. Hence, ramifications of a small pressure change can be seen through out the cycle. CE make Korba Boiler is not designed for Sliding Press. Operation.

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Re-heater Line Pressure Drop: On account of reducing slope of temperature line with respect to consistent slope of condenser pressure line, the turbine expansion line ABCHI (under ideal 'no pressure drops' conditions) denotes optimum heat drops across HP/IP turbines. However a practical steam turbine has about 5% to 7% pressure drops in reheat line. Subsequently turbine expansion lines now become ACCDEFG, which indicates a far less efficient steam utilisation It must always be ensured that cold reheat NRVs are functioning freely. Opening out along the steam flow.

Also reheat pressures along with HPT exhaust pressure at various load must be recorded for a healthy machine so that the same can be used for comparisons at a future date. Throttle governing In modern, large machines the economic rating coincides with the maximum rating. The steam flow is controlled by the degree of opening of the throttle valves, which are located in the HP cylinder steam chest. Obviously the up-stream steam pressure at the throttle valves will be constant, irrespective of the turbine load, but the pressure after the throttle valves will reduce as the valve opening reduces. This will cause the available energy per kilogram of steam due to expansion to be reduced, as well as the mass flow of steam. This is illustrated for a non-reheat turbine the in fig. The turbine stop valves conditions are 105 bars and 565 oC. At full-load, the loss of steam pressure due to the throttling effect of the turbine stop and throttle valves is about 5%. Hence the after throttle valve (ATV) pressure is, say, 100 bar absolute. The steam does work in the turbine by expansion until 40 m bar backpressure is reached, the state-point of the steam being represented by the line AB, representing 80% efficiency. At halfload, the ATV pressure will be half of that at full-load, as shown at C. The expansion of the steam is shown from C to D. Specific Entropy vs Enthalpy steam state-point lines in throttle governing

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Similarly, for 25% load, the ATV pressure will be a quarter of full load and the expansion EF. Notice that the specific enthalpy of the inlet steam remains unaltered for the range of loads. However, the available energy is reduced significantly as the loading falls, as shown in Table. Heat drop per Kg of steam at various loads (at 80% efficiency) Load

Enthalpy KJ/Kg Heat drop KJ/Kg at inlet at exhaust 100% 3357 2343 1194 50% 3537 2419 1118 25 % 3537 495 1042 This reduction of heat drop, coupled with the reduced flow of steam, causes the turbine output to be reduced as the throttle valves close. Notice that the slope of the expansion line remains the same for all loads, so the efficiency of the expansion remains the same, which is what one would expect from the earlier discussion about cylinder efficiency. On the other hand, it should be realised that throttling incurs losses as the steam pressure and temperature are adversely affected. Nozzle Governing Here the first-stage nozzles are divided into a number of groups, sometime more than ten. The steam admitted to each a valve controls group, and each valve is opened in turn as loading is increased as shown in the fig. Consider a four-valve arrangement where the first valve only is in service from no-load to quarter-load, and at quarter load it is fully open. This is followed by the second half-load, and then valves three to three-quarter load. Finally, the last permits maximum loading when fully open. The only valve operating in the throttling mode is the last one to be brought into service, all the previous ones being wide open, so the losses due to throttling are not so great as with the previous type, so operation is more efficient. This is illustrated in the fig where the conditions are similar except for the governing used. At fullload, the expansion is from A to B, similar to the previous example. However, at 50% load, only two valves are open, but again a pressure of 50 bar is required. This is achieved more efficiently than before, so the line for two nozzle operation is shown from A to C. Thereafter the expansion is from C to D. Similarly one nozzle operation is shown from A to E, and hence from E to F.

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Nozzle governing differs from throttle governing as follows: *The turbine efficiency is higher at part-loads because of reduced throttling loss *The va.lve control gear is more complicated. *The internal efficiency of throttle and nozzle governed machines can be the same (Represented by slope of the expansion lines on H-S diagram) after the wheel case. *Because of their improved part-load efficiency, nozzle-governed machines are preferable where the loading regime involves prolonged operation under these conditions. ESV/RH Steam Temperature Variations in steam temperature results in variations of specific volume of the steam and this result in change of steam flow according to Fa = Fo*{(Pa *Vo)/ (Po * Va)} 1/2 Where F=flow, P= Pressure, o= Optimum condition; V= Sp. volume of steam of ESV a= Actual condition Other effects for reduced steam temperature for a non-reheat set are: a. b. c.

Total energy-reduces hence turbine efficiency is also reduced. Wetness increases at the exhaust of L.P.T. turbine. Change of flow and pressure of steam.

For reheat machines as shown in the figure reduction of main steam temperature causes available energy of steam to be reduced causing reduction in efficiency. Also, extra heat is required in reheater to have the same hot reheat temperature. Expansion in IP/LP turbine remains unchanged as long as HRH temperature is constant:

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If the reheater temperature is reduced and MSV temperature is constant, IP/LP turbine output reduces due to less available heat drop, exhaust wetness increases and heat addition in R/H is reduced. The HPT is not affected. High temperature yield high heat drops but cause significant reduction in operation life of high temperature components.

Effect of Inlet Temperature changes 570 560 580 570 570 ATV tem eratureoC 570 570 570 560 580 Reheater tem eratureoC 29.0 29.0 29.0 29.0 29.0 Exhaust tem eratureoC Exhaust wetness % 14.7 14.7 14.0 15.1 14.1 Heat drop in HPC KJ/Kg 421.8 414.8 428.3 421.3 421.8 Heat drop in R/H KJ/Kg 1407.4 1407.4 1407.4 1394.3 1422.9 Total heat drop 1829.2 1822.2 1835.7 1816.1 1844.7 Note that the effect of reducing the ATV temperature to 560 OC is significant with reference to total heat drop even though it only affects the HP cylinder heat drop and does not affect the wetness. Steam Attemperation Attemperation of steam invariably causes loss of power output and increase in heat rates. But is not entirely avoidable in modern high capacity boilers. Especially reheat attemperation should be avoided until absolutely necessary. As far as possible, the reheater steam temperature should be controlled by the burner tilt. The basic objection to reheat attemperation is that the steam so formed does work only in IP and LP turbines bypassing the HP turbine; hence there is a considerable reduction in cycle efficiency.

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Feed Water Temperature The feed water temperature at boiler inlet is another main important factor determining cycle efficiency. It is mainly dependent on a. Heater performance. a. Feed flow through heaters. c. Terminal Temperature difference (outlet feed water temperature steam saturation temperature at the extraction pressure). d. Bled steam pipe pressure drop. e. Steam temperature at heater inlet. One degree centigrade rise in TTD (Terminal Temperature Difference) leads to 0.027% drop in efficiency. A bad heater performance can be attributed to the following: - Air blanketing - Waterside contamination. - Steam side contamination. - Drainage defects.

In order to avoid this factor, the boiler must be operated at constant pressure, so that feed flow remains optimum. Proper and frequent air venting of heaters, prevention of oxygen ingress and thus exfoliation i.e. flaking of tubes causing subsequent choking and TTD increase; and maintaining of proper pH value in Condenser should be practiced. Boiler Excess Air Boiler combustion efficiency largely depends upon supplying adequate quantity of excess air, too much of which results in increased dry flue gas losses and flame instability, leading to poor efficiency and reliability of operation. Too much of excess air can be through ingress points such as a. Suction milling plants. b. Expansion joints on ducts. c. Openings like peepholes. d. Ash hopper doors open. e. Ash hopper seals. These leakages put extra burden on ID Fans and limitations on unit loading. The leakages after air pre-heaters do not affect the efficiency significantly.

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Air Pre-heaters Gas Outlet Temperatures Low air pre-heater gas outlet temperature may be due to the following: a. b. c.

Light up of cold boiler. Excessive air leakage in the APHs (damaged seals). Very high wind box pressure.

d.

Inadequate air supply in boiler.

e.

Poor fuel quality.

f.

Air pre-heater sooting.

High APH gas temperature may be due to a. b.

APH sooting or ineffective soot blowing. Holed and torn element at cold ends, due to corrosion.

c.

Sooting of boiler.

d.

Excessive air supply to boiler.

e.

Film boiling due to poor circulation in boiler.

f.

Low feed water temperature.

g.

Poor milling and longer burn-off times of coal.

h.

Use of higher elevation burners at low loads.

i.

Excessive firing.

j.

Air ingress into furnace.

Generally speaking a 20 efficiency.

OC

rise in final gas temperature causes a drop of 1% in

DM Water Make-up Rate DM water make up is a must in modern power station due to certain problems which warrant invariable blow-downs soot-blowing etc. There are four usual sources of loss Soot blowing Soot blowing must be done selectively and only when required. Frequency of soot blowing is also dependent upon coal quality and furnace temperature and firing configuration. Boiler Blow down During initial start-ups it is unavoidable, hence very conditions that lead to outages must be avoided. On load condition it is a loss of DM water and useful heat. So all attempts should be taken to keep dust ingress into the boiler water to a minimum, and to have good boiler water chemistry. A good maintenance schedule to prevent any leakage or passing of valves must be KORBA SIMULATOR

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envisaged. The operators must take due care to avoid any undesirable overflowing of DM storage tank, deaerator, drum etc. Auxiliary Power Consumption These are the following factors consumption.

contributing

to

excessive

auxiliary

power

Machine Loading As the unit load is decreased, percentage aux. power rises as shown in the fig. In common practice, operator must have three mills running at full load rather than four mills running at part capacity. CW pump flow must be controlled in accordance with optimum backpressure requirements so that benefits from running equipments should be more than the cost of running them. Variable Speed Drives Power consumption of variable speed drives varies as the cube on the speed. Hence, precaution must be taken to affect only the minimum speed, which will do the job. For example, BFP discharge should be maintained to give the lowest required differential pressure across feed water station at any load. Parallel Operation of Auxiliaries Two pumps in parallel do not give twice the output of one pump. In fact it is quite common to derive only marginal increase by running second pump and adds to higher auxiliary power consumption, which reduces overall station efficiency. Milling Plant Power Consumption Attempts should be made to run the existing mills at full load rather than starting new mills to be run at part load. Moreover, classifier settings should be regularly checked to give just the required fineness of coal, not more. More fines puts extra burden on the pulverisers. Mill outlet temperatures must be maintained at the rated value. Low temperature puts a limitation on loading of the mill. High mill reject operation puts extra burden on PA Fans and also it is a loss in terms of loss of some pulverized coal from the mill.

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Unit Loading The efficiency of a unit improves as the loading improves. So, all out attempts must be made to ensure, there is no part loading or outages to maintain a high load factor, and shortfalls should be kept to minimum. Because fixed heat has to be sustained at all loads. It is important to generate every possible megawatt while on high load. One important way of preventing short-falls, is to ensure that boiler firing must be controlled to control boiler pressure not, by varying l oad on T/G. CONDENSER PERFORMANCE Even a small worsening of backpressure is very expensive in terms of extra heat required for a given output. To illustrate this for a 200MW station, if the backpressure worsened by just 100 mm (Hg.), the resulting extra fuel cost would be about Rs. 6,000,000/- per annum. Hence condenser performance is undoubtedly the most important operating parameter on a unit. So the factors affecting backpressure must be clearly recognised so that effective remedial measures can be taken once they are detected. It is evident that work obtained from the turbine increases if backpressure is reduced. So it is always desirable to operate at minimum economic backpressure i.e. condenser temperature is as low as possible. If the condensing surfaces were infinitely large, condensing temperature would equal the CW inlet temperature. However there is a practical limit and in practice the average condenser temperature is 15OC above the inlet CW temperature, but even then the size of condensing plant is considerable. For example, on 660 MW unit the condenser may have 20000 x 25 mm diameter tubes, each 20m long. Reason for this is apparent when we realise that for generated output of 660 MW, 780 MW is surrendered to the condenser. Determination of deviation The manufacturer supplies various performance curves for the condensing plant, which should be verified by test as soon as possible. Two important relationship must be established - load vs. CW temperature rise and load vs. terminal temperature difference.

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Knowledge of these optimum values is basic to much condenser performance. Importance of CW temperature is obvious but TTD (Terminal Temperature Difference) needs a bit of understanding. To make heat flow from condensing steam to cooling water requires some temperature gradient, steam temperature being higher than that of cooling water. Excellent heat transfer requires small gradient whereas bad heat conduction requires a large gradient. Hence TTD is a measure of effectiveness of heat transfer. Condenser condition graph

As has been explained the backpressure in condenser depends mainly on-

Variation of CW inlet temperature

-

Variation of CW flow

-

Interference with heat transfer

Effect of these factors can be illustrated with the help of condenser condition graph shown in the adjoining fig. For example optimum and actual conditions for a KORBA SIMULATOR

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condenser are listed below. Parameter CW inlet temp. oC

Optimum 16.5

Actual 20.0

-

CW outlet temp. oC

25.0

26.0

-

CW temp. rise oC

8.5

6.0

-

Saturated steam temperature corresponding to back pressure oC

30.5

36.0

-

TTD. oC

5.5

10.0

-

Back pressure mbar

43.7

59.4

To determine the contribution of each of the main factor to the total deviation in backpressure from optimum we can use condenser condition graph. Contribution due to CW inlet Temperature Plot a line vertically from actual CW inlet temperature point up to the optimum CW rise line and then horizontally to the optimum TTD. From this point drop a vertical line to intercept the saturation temperature line at 34 OC with corresponding backpressure of 53.2 mbar. So the backpressure deviation due to CW inlet temperature alone is (53.2 - 43.7) = 9.5 mbar. Contribution due to incorrect CW flow In the list it can be seen that actual rise is less, hence the CW flow must be more than optimum. To determine its component affecting backpressure, plot a line from actual CW inlet to actual CW rise, then to optimum TTD line, finally downward to cut saturated steam temperature line at 31.5 OC. Equivalent backpressure is 46.2 mbar. Therefore, the pressure deviation due to high flow is 46.2 - 53.2 = 7 mbar. High CW flow improves the backpressure by 7 mbar. Contribution due to heat transfer Deduct from actual backpressure of 59.4 the backpressure of 46.2 (= 13.2 mbar). This is the deviation caused by high TTD. Shift Monitoring For this purpose, the required curves are CW temperature rise v/s. load, optimum TTD v/s. load (both have been illustrated earlier) and target back pressure for various CW inlet temperature v/s, load.

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Once per shift during the period when load is steady, backpressure on the unit should be monitored to determine backpressure deviations and their removal. A standard form can be used as shown below (typical for a 500 MW set). The air suction temperature is required because it is an indication of air ingress to the condenser. For example if there were no air ingress, air suction temperature of vacuum pump inlet would be 4-5oC lower than t he saturated steam temperature. Air ingress causes the temperature or the suction of vacuum pump to fall further as per 'Dalton's Law of Partial Pressure. The total pressure of inlet to the pump is made up of partial pressure of air and water vapour. But the temperature of mixture is due only to the water vapour. Consequently as the vapour quantity is reduced, so is the temperature. The effect of internal tube deposits and the effect of air blanketing on outside of tubes are indistinguishable in their effect on TTD. Hence, when the air ingress is ascertained and rectified, then any deviation in back pressure ascribed in air/dirty tubes will be due only to the dirty tubes and hence a decision can be taken to clean dirty tubes. SPOT BACK PRESSURE CHECK UNIT NO. 1.

DATE

Actual back pressure

mbar

2.

Saturated steam temperature

oC

33.7

3.

CW inlet temperature

oC

17.9

4.

CW outlet temperature

oC

26.8

5.

Exhaust steam temperature

oC

33.7

6.

Condensate temperature

oC

34.9

7.

Air suction temperature

oC

24.9

8.

CW outlet valve position

%

55%

9.

Target back pressure

mbar

48.4

10.

Optimum CW temp rise

oC

9.0

11.

Optimum TTD

oC

5.2

12.

Back pressure due to CW inlet = (3) + (10) + (11)

mbar

47.8

13.

Back pressure due to CW flow = (4) + (11)

mbar

47.5

mbar

-0.6

14.

Variation due to CW inlet temperature = (12) - (9)

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283

15.

Variation due to CW flow = (13) - (12)

16.

Variation due to air/dirty tubes = (10 - (13)

17.

BP variation = (1) - (12)

18.

No of air pumps in service

mbar

-0.3

mbar

4.8

mbar

4.5

FEED WATER HEATER PERFORMANCE In modern power stations direct and indirect feed water heaters are invariably in use to enhance the unit performance. Usually the number of feed water heaters provided on a power plant depends on the trade off between the full costs saved by a particular no of heaters balanced against the annual fixed charge on heater investment for minimum generating cost. Economically justifiable maximum number of heaters on a plant is ten. It is common to find 6-7 feed water heaters on power generating units in our country. Heat transfer to feed water in non-contact type heater is achieved by the surrender of latent heat of steam primarily because heat recovery by de-superheating and drain cooling is about 6%-8% of the total latent heat recovered by feed water. The two important parameters used in assessing heater performance are TTD (Terminal Temperature Difference) and Drain Approach. TTD is defined as the difference between saturation temperature of extraction steam and feed water temperature after the heater. Where as drain TTD or drain approach is defined as difference between feed water temperature at inlet to heater and drain outlet temperature after the heater. Factor Causing Deterioration of Heater Performance It is not sufficient to just measure final feed water temperature to determine if the heaters are operating efficiently, because trouble at one heater can be compensated for by other heaters doing more work. This causes bled steam flow to heaters, to alter and thus affect the work done. So cycle efficiency is altered. Therefore, it is necessary to check individual heaters from time to time, checking particularly the TTD and drain approach as a general rule, preferably twice in a year, heaters (individually) investigation must be carried out. Deterioration of heater performance occurs on account of one or more reasons as shown below: • Air accumulation •

Steam side fouling

• Water side fouling •

Drainage defects.

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Air Accumulation Air is a superb thermal insulator, hence, highly undesirable. Proper vents are generally provided on heaters (to condenser) body to prevent accumulation of air. Air can get into heaters when extraction pressure in them is reduced below atmosphere i.e. wherever the machine load is reduced or machine is off-loaded. Hence, the vents of sub-atmospheric heaters must be permanently open while those on the rest should be open long enough to vent them thoroughly while machine comes on load and periodically thereafter. It needs to be emphasised that steam (generally 0.5%) passing through the vents is a loss to the system. Accumulation of air manifests itself in the following: •

Reduced drain approach.

•

Increased TTD

•

Elevation of steam to heater temperature.

•

Reduced temperature rise of feed water heater.

Steam Side Fouling Cupro-nickel (70/30) alloys was generally used in the past. However, it was found that this material exfoliates (i.e. it flakes off like a dead skin). Due to this the space between the tubes in the cluster becomes blocked with debris and heat transfer is progressively reduced. It has been practically established in one case that TTD rose from 4 OC to 14 OC continuously over a period of 7 years. Alternatively now 90/10 cupro-nickel, Monel metal, mild steel etc. are used as tube material to reduce problems of exfoliation. The effect of exfoliation include: •

Progressive increase of TTD.

•

Drain temperature of unaffected.

•

Reduced feed temperature rise

•

Eventual tube failures due to weakening

• Accumulation of debris in heater shell. When the heater is out of service, it is important that there is no standing water at tubes such as those in the drain cooling section to prevent corrosion. Also, oxygen percentage must be kept under recommended units to keep the rate of corrosion to minimum. Water Side Fouling Most common cause of waterside fouling is oil. Oil can get into the system from leaking bearings and important gland seals of LP turbine. Deposition of them occurs in HP heaters affecting them all but being worst at the highest-pressure heater. Thermal manifestations of troubles are similar to those for exfoliation except that the KORBA SIMULATOR

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onset of increasing TTD is usually sudden and rate of deterioration is rapid. Slightly fouled tubes can be chemically cleaned. In the worst cases high pressure water jetting may be required. Drainage Defects Apart from obvious problems such as passing valves etc. the usual troubles are due to a. Damaged flash box internals b. Reduced/enlarged orifice opening c. Heater drains pump defects. A typical flash box has an orifice followed by a diffuser, which diverts the flashing drain downward on to water reservoir. If the diffuser disintegrates, its pieces can create obstruction in pipes and cause flooding. Further flashing steam/water may cause erosion of flash box internals. Reduction due to fouling, of the orifices is very common. It results in drain blocking up to previous flash box resulting in flooding and some water droplets are carried into flash steam to the bled steam pipe. Heat is taken up by the water and steam to heater temperature drops. Conversely, orifice size can increase due to erosion and can reduce differential pressure from inlet to outlet. The orifice plate does not alter the bled steam pressure at upstream and downstream heater so the reduced differentials achieved by lowering the water level in upstream heater. Sometimes high-pressure heater drain cascade to a drain pump which pump it to deaerator. At deaerator pressure the O

saturation temperature is of the order of 160 C approx. and if the pump suction head is not sufficient then water can flash in the pump itself interfering with the pumping. This causes heater level to rise; consequently drain to condenser opens up and results in lowering heater efficiency. Effect of Heater out of Fouling Fouled heater gives increased TTD, as is already evident i.e. lower feed water out temperature. This relatively cold water goes to the next heater, which has to work harder to maintain its TTD and draws more steam in the process. This steam is not available for doing work hence cycle efficiency is lost. Increased steam flow also causes mechanical damage to the nearing tube bundles because of increased velocity and mass flow. Effect of Heater out of Service Anyone heater being out of service considerably affects the cycle efficiency. Feed water outlet is lowered and the next heater has to do extra work as is explained earlier. If the final (highest pressure) heater is taken out the feed water to boiler is at lower temperature and has to have extra heat given to it in the boiler. Further bled KORBA SIMULATOR

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steam, which is now not being bled, can do extra work in the turbine, significantly improving the unit output although at the expense of lower thermal efficiency. (Incremental heat rate of the additional MWs is very high hence this is a very expensive method of generation). As a general guide to the effect of having a heater out of service, the following efficiency reductions may be used.

TSV pressure

Up to 100 bar

over 100 bar

L.P. Heater

0.5%

0.5%

Last HPH

1.3%

1.5%

Monitoring of Feed Water System Feed heater surveys can be conducted every six months to detect any early deterioration of heater performance. Operations staff must keep a routine check of the performance on a shift-to shift basis noting down final FW temperature, heater TTD and steam-to heater temperature. Feed Water Chemistry (High Oxygen Regime) Magnetic layer, against corrosion by feed water, protects low alloy/mild steel tubes. O

O

At temperature between 140 C and 200 C magnetic layer is more porous than it would be if it is formed under higher temperature. Since it has slight solubility it can be removed by turbulent/ past feed flows in heaters. A fresh layer is formed and eroded and go on causing metal loss at bends and bifurcations. To deal with these problems, 20-150 micro gm. per litre of oxygen is injected into feed water before heater drain. This oxygen causes iron oxide to be deposited as hematite. To save this layer of hematite feed water should have low anion content (low chlorides, sulphate), or i.e. should have low after cation conductivity, usually below 20 micro siemens /m. This can be achieved by good condensate polishing.

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SIMULATED MALFUNCTION LIST

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LIST OF SIMULATED MALFUNCTIONS BOILER SYSTEM MALFUNCTIONS B01

Pulveriser A to F choking or loading up

B02

Coal Feeder A to F trip

B03

Pulveriser A to F trip

B04

Pulveriser A to F Fire

B05 B06

Pulveriser A to F reduced capacity Coal Feeder A to F fail to deliver coal

B07

Water Wall Tube leakage

B08

A or B ID Fan trip

B09

A or B FD Fan trip

B10

A or B PA Fan trip

B11

A or B I D Fan out board bearing temp. high

B12

A or B FD Fan outboard bearing temp high

B13

A or B PA Fan outboard bearing vibration high

B14

A or B I D Fan outboard bearing vibration high

B15

Flame Scanner Elevation AB, CD or EF shows flame continuously

B16

Fuel Flow run back to less than demand

B17

Drum Steam Pressure Transmitter fails low

B18

Low Drum level

B19

RH Tube leakage

B20

Secondary SH Tube leakage

B21

Electromatic Safety Valve fails open

B22

APH Primary Air Output Damper AD-20 fails closed

B23

Pulveriser A to F tempering Air Damper froze

B24

Plugged Air Heater

B25

Aux Air Dampers adjacent to coal elevation faulty modulating

B26

FSSS AC Supply fail

B27

FD Fan A or B Discharge Damper AD-3 / AD-4 fails closed

B28

Aux Air Dampers not modulating

B29 B30

Drum Emergency blow-down Valve B-82 or B-83 fails open Left side Furnace Pressure low

B31

Burner Tilt fails high

B32

HO Header Pressure low

B33

HO Trip Valve fails closed

B34

HO Temperature low

B35

HO Supply Header Pressure low

B36

Aux PRDS Valve fails closed

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B37

A or B APH main drive motor trip

B38

Firing Rate limited

B39

Airflow run back to less than demand

B40

I D Fan A or B Inlet Vane froze

B41

High Drum Level

B42

High SH tube metal temp

B43

Boiler Water Silica concentration high

B44

Throttle Pressure Transmitter fail

B45

Loss of Seal Air to Pulveriser A to F

B46

Airflow less than 30%

B47

Airflow more than 40% during start-up

B48

All Pulverisers trip

B49

Boiler Purge Timer failure

B50

Flame Scanner failure, elevation AB, BC, DE and EF

B51

Ignitor pair 1 and 3 of elevation AB, CD and EF fail Off

B52

Elevation AB Oil Gun # 1 Scavenging Valve stuck open

B53

No Start Permissive for Pulverisers A to F

B54

Pulveriser A to F Primary Airflow Temperature Thermocouple fail

B55 B56

Pulveriser A to F Hot Air Gate fails closed Pulveriser A to F motor stator temperature high

B57

Pulveriser A to F Airflow feedback offset 25% high

B58

Pulveriser A to F fails to start

B59

Loss of Coal Flow Indication of Feeders A to F

B60

Loss of Drum Level Transmitter

B61

Furnace walls badly slagged

B62

Abnormal Ash build-up on RH pendant

B63

Ash build up in Economiser

B64

PA Header Pressure Controller malfunction

B65

Furnace Pressure Controller A or B malfunction

B66

Purge Ready condition cannot be met

B67

Air Heater A or B fire

B68

Aux Air Damper control power failure

B69

Burner Tilt position difference

B70

ACS Power Supply failure

B71

Boiler Master Controller failure

B72

Economiser Tube leakage

B73

A or B SH Attemperation Spray Block Valves fail closed

B74

A or B RH Spray Valve fails

B75

Failure of Final RH Temperature Controller

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B76

SH outlet steam temperature swinging

B77

RH outlet steam temperature swinging

ELECTRICAL SYSTEM MALFUNCTIONS E01

Stator Cooling Water tube leakage

E02

Hydrogen Cooler tube leakage

E03

Loss of Hydrogen Seal Oil pressure

E04

Generator Hydrogen leakage

E05

Generator Cold Gas temperature high

E06

Low Stator Cooling water flow

E07

Loss of Outside Power to buses 1A or 1B

E08

Generator Trip

E09

Generator Auto Voltage Regulator failure

E10

Grid Frequency drops down to 49.5 Hz

E11

System Voltage drops low

E12

Loss of Generator Excitation

E13 E14

Unequal Generator Phase Loading Loss of 220V DC bus to FSSS

E15

Loss of 415 V AC Bus

E16

Loss of Normal Power to Emergency Bus

E17

Megawatt Transducer fails

E18

Low Stator Water Resistance

E19

Loss of one Hydrogen Cooler

E20

Generator Bearing # 1 babbit temperature

E21

High Stator Cooling Water Temperature

E22

Seal Oil leakage into the generator

E23

Auto Synchroniser failure

E24

Generator Seal Oil temperature high

E25

Main Power Transformer oil temperature high

E26

UAT A or B failure

E27

Loss of Emergency Supply Power

E28

Generator Auto Voltage Regulator oscillating

E29

DC Seal Oil Pump fails to start

E30

Stator Cooling Water Pump A or B trip

E31

220V DC Bus fuse blown

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FEED WATER SYSTEM MALFUNCTIONS F01

Loss of CW Pump 1-3

F02

HPH-6 Extraction Valve fails closed

F03

LPH-3 tube leakage

F04

HPH-6 tube leakage

F05

HPH-6 alternate drain valve fails open

F06

HPH-6 normal drain fails closed

F07

HP heaters Group Bypass Valve fails open

F08

BFP A-C Re-circulation Valve fails closed

F09

BFP A-C Speed Controller failure

F10

Fluctuating FW Control Valve

F11

One FW Regulating Valve fails open

F12

BFP A-C loss of Oil Pressure

F13

BFP A-C high Bearing Vibration

F14

BFP A-C loss of Suction

F15

BFP A-C Re-circulation Valve fails open

F16

Condensate Re-circulation Valve MC-33 fails open

F17

DA Overflow Valve failure

F18 F19

DA Level Control Valve MC-41 fails open DA Extraction/Pegging Steam Valves AS-62/ES-7 goes closed

F20

DA level transmitter used for ACS, freezes at present level position

F21

Condensate Surge Tank low level switch (DC 43) fails

F22

Hot Well level high

F23

Hot Well level transmitter failure

F24

Condenser Tube leakage

F25

Condenser Air leakage

F26

CEP A or B trip

F27

LPH-3 Extraction Steam Valve fails closed

F28

BFP A-C trip

F29

BFP A-C Hydro coupling Oil temperature high

F30

LPH-3 Normal Drain level controller failure

F31

DA Pressure Controller failure

F32

CW Differential Pressure high

F33

HPH-5 Extraction Valve fail to close on demand

F34

Condensate Re-circulation Valve fails closed

F35

HPH-5 Normal Drain Valve fails closed

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TURBINE SYSTEM MALFUNCTIONS T01

Turbine AOP A or B trips

T02

Low Secondary Oil pressure to Intercept Control Valve

T03

Gland Steam Condenser tube leakage

T04

Loss of Gland Sealing Steam

T05

Gland Steam Pressure high

T06

Emergency Stop Valve # 2 fails closed

T07

Intercept Stop Valve # 1 fails closed

T08

Turbine Control Valve malfunction

T09

Loss of Exhaust Hood Spray

T10

Turbine Shaft Oil Pump fails

T11

Low MOT level

T12

Turbine Bearing Vibration high

T13

ATRS Sub Group Control Turbine failure

T14

ATRS Sub Loop Control Drains failure

T15

Loss of TSI Power

T16

Broken last stage turbine blade

T17

Main Turbine EHG control fails high

T18 T19

Main Turbine Thrust Bearing temp signal monitor fails high Turbine Axial Shift high

T20

Turbine Over Speed

T21

Main Turbine Lub Oil Cooler cooling capacity reduced

T22

Barring Gear Valve stuck closed

T23

HPT Differential Expansion high

T24

Turbine EOP fails to auto start

T25

Condenser Back Pressure high

T26

Turbine Thrust Bearing Trip Device faulty

T27

Seat Drain Valve before Emergency Stop Valve will not open

T28

Loss of 415 V AC to turbine EHG system

T29

Turbine Initial Pressure Limiter (IPL) transmitter fails low

T30

Turbine trip

T31

HP Bypass Valve fails open

T32

LP Bypass Spray Valve fails closed

T33

Water in turbine Inlet Steam

T34

Turbine Stress Evaluator failure

T35

LP Bypass fails to open on demand

T36

HP Bypass fails to open on demand

T37

Turbine Lub Oil Pressure controller failure

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T38

Turbine Lub Oil Pressure Low trip device faulty

T39

ATRS Control Power failure

T40

ATRS Sub Group Control fails

T41

Low Vacuum Trip Device fails to function

T42

Plugged Oil Line disarms Trip Devices

MISCELLANEOUS SYSTEM MALFUNCTIONS M01

Loss of Station Air Pressure

M02

Loss of Instrument Air Pressure

M03

Aux Cooling Water Pump Motor A or B trips

M04

Loss of Aux Steam

M05

Stuck Water wall Soot Blower (B-8)

M06

APH A or B Cold End temperature low

M07

Loss of Gland Steam Vapour Extractors

M08

Loss of MOT Vapour Extractor A or B

M09

Scanner Air Fan A or B trips

M10

UPS Power failure

M11 M12

Loss of Soot blowing steam Retractable Soot blower (R-4) failure

M13

APH Air Motor A or B fails to auto start

M14

Hydrazine BD Valve's CRH temperature interlock bypassed

X01

HP Bypass BD Valve’s CRH temperature interlock bypassed

X02

Starting Device frozen

X03

Mill A trip

X04

Mill B trip

X05

Mill C trip

X06

Mill D trip

X07

Mill E trip

X11

FD Fan-B trip

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APPENDIX

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APPENDIX

TITLE

Pag

1.

Load Vs Superheater outlet Pressure

327

2.

Boiler Load Vs Airflow

328

3.

Wind box to Furnace DP Vs Load

328

4.

Load Vs Superheater and Reheater Temperature & Spray

329

5.

Deaerator Pressure Vs Load

329

6.

Drum Pressure change during start-up and shutdown

330

7.

Boiler start-up after 250 hours shutdown

331

8.


332

9.


333

10.


334

11.

Turbine start-up curves

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ASSUMING SUITABLE PRESSURE DROP IN THE MS LINE FOR THE VARYING FLOW CONDITIONS

LOAD Vs SUPER HEATER OUTLET PRESSURE (PREDICTED)

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WIND BOX TO FURNACE DIFFERENTIAL Vs LOAD

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LOAD Vs SUPERHEATER AND REHEATER TEMPERATURE

DEAERATOR PRESSURE Vs LOAD CURVE

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MAXIMUM ALLOWABLE RATE OF PRESSURE CHANGE FOR NORMAL START-UPS AND SHUTDOWNS

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BOILER START-UP CURVES AFTER 250 HOURS SHUTDOWN

NOTE: 

Aux steam is available from external source



The Deaerator drawl from CRH is expected to cut in after synchronisation and at least 20% loading is done.



Steam temperature downstream of HP Bypass

HP Heaters from CRH may cut in afterwards at 30%

need not be regulated by spray until the MS Temp is

load.

above 300OC. Then HP BP downstream temp may be regulated to 230OC.



SH Spray need not be used for controlling SH outlet temp until the boiler flow is at least 160 T/H. SH & RH temp may be regulated and allowed to raise along the suggested curve at higher loads.

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NOTE: The metal temp anticipated: HP Casing: 140 OC



ST Valve:



50OC

The Deaerator drawl from CRH is expected to cut in after synchronisation and at least 20% loading is

Boiler : Ambient.

done. HP Heaters from CRH may cut in afterwards at 30% load.



Aux steam is available from external source. 



Steam temperature downstream of HP Bypass need not be regulated until MS temp is above 300 OC.

Then this may be regulated to 230 OC.

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SH Spray need not be used until the boiler flow is at least 160 T/H. SH & RH temp may be regulated and allowed to raise along the suggested curve at higher loads.

303


NOTE: 

The metal temp anticipated: HP Casing: 350 OC ST Valve: 210

at least 120 T/H.

Steam temperature downstream of HP Bypass need



SH Spray need not be used until the boiler flow is



OC.

Aux steam is available from external source.



not be regulated until 90 T/H bypass flow is established. Afterwards this may be regulated to 260 OC.



Deaerator is to be kept pegged at 140 OC minimum before firing the unit.



Only Deaerator steam is extracted from CRH. HP Heaters are anticipated to be put into service only after synchronisation.

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Reheater temp control by spray may be adopted if required, after HP bypass closes.

304


NOTE: The metal temp anticipated: HP Casing: 465 OC





Full vacuum should be available before firing.

ST Valve: 410OC. 

Aux steam is available from external source.



SH Spray need not be used for controlling SH

outlet temp until the boiler flow is at least 160 T/H. SH & RH temp may be regulated and allowed to raise



Deaerator is to be kept pegged at 140

OC

along the suggested curve at h igher loads.

minimum before firing the unit.  

Steam temperature downstream of HP Bypass need not be regulated until 50 T/H bypass flow is

Turbine can be loaded along the dotted line i.e. 21 MW/Minute. For this, the boiler should be at rated parameters before rolling using HP and LP bypass.

established.

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TURBINE START-UP CURVES Warming-up and Starting the Turbine Temperature Criteria

Fig: 1

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Fig: 2 RECOMMENDED MINIMUM CURVE (CURVE-A) AND MAXIMUM (CURVE-B) MAIN STEAM TEMPERATURE AHEAD OF TURBINE WHEN OPENING THE MAIN STOP VALVES.

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Fig: 3 ALLOWABLE MAXIMUM MAIN STEAM PRESSURE AHEAD OF TURBINE WHEN OPENING THE MAIN STEAM STOP VALVES.

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Fig: 4 RECOMMENDED MINIMUM MAIN STEAM TEMPERATURE AHEAD OF TURBINE BEFORE OPENING THE MAIN CONTROL VALVES

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Fig: 5 RECOMMENDED MINIMUM REHEAT TEMPERATURE AHEAD OF IP TURBINE BEFORE OPENING THE REHEAT CONTROL VALVES

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Fig: 6 RECOMMENDED MAXIMUM MAIN STEAM TEMPERATURE AHEAD OF TURBINE BEFORE THE TURBINE IS BROUGHT TO RATED SPEED

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Fig: 7 RECOMMENDED MAXIMUM MAIN REHEAT TEMPERATURE BEFORE TURBINE IS LOADED

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200MW Trainig Simulator Volume 2

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