PRESENTATION ON ELECTRO HYDRAULIC CONTROL SYSTEM

By Ashvani Shukla C&I Reliance

EHTC = ELECTRO-HYDRAULIC TURBINE CONTROLLER

IT IS THE GOVERNOR FOR TURBINE.

SYSTEM SUPPLIED BY BHEL-EDN, BANGALORE.

IMPLEMENTED IN THE METSO DNA DCS.

CONTROLLERS IN EHTC• SPEED CONTROLLER – (MODES: PI, PD)• ISOCHRONOUS FREQUENCY CONTROLLER• LOAD CONTROLLER• EXTRACTION-1 (IP EXTRACTION) CONTROLLER • EXTRACTION-2 (LP EXTRACTION) CONTROLLER

EHTC

RATIO

SETTER

MAX

MIN

SPEED CONTROLLER

PI/PD MODE

LOAD / ISO FREQ CONTROLLER

 

SPEED REF

LOAD REF

LOAD ACTUAL

SPEED ACTUAL

SPEED/LOAD LIMITERLIMIT REF

EXTRACTION-1 PRESSURE CONTROLLER

PRESSURE REF

PRESSURE ACTUAL

MIN

EXTRACTION-1 PRESSURE LIMITERLIMIT REF

EXTRACTION-2 PRESSURE CONTROLLER

PRESSURE REF

PRESSURE ACTUAL

MIN

EXTRACTION-2 PRESSURE LIMITERLIMIT REF

VALVE CHARACTERISTIC COMPENSATOR

HPCV LIFT REFERENCE

IPCV LIFT REFERENCE

LPCV LIFT REFERENCE

FREQ REF

FREQ ACTUAL

EHTC BLOCK DIAGRAM

EHTC FUNCTIONS

ROLLING WARM UP CRITICAL SPEED AVOIDANCELOAD / SPEED CONTROLEXTRACTION PRESSURE CONTROLISLANDING

TURBINE AUXILIARIES ARE STARTED, I.E. LUBE OIL SYS, CONDENSATE EXTRACTION SYS, ETC.

TURBINE PROTECTION IS RESET FROM ABB DCS AFTER FULFILLING THE CRITERIA

THE EMERGENCY SHUTOFF VALVE (ESV) IS OPENED

DEPENDING ON THE SHUTDOWN DURATION, THE TYPE OF TURBINE STARTS ARE AS FOLLOWS:

1. COLD START: AFTER 250 HOURS2. WARM START: AFTER 40 HOURS3. HOT START: AFTER 16 HOURS

WARM UP / SOAK TIME IS REQUIRED AS ROTOR EXPANDS FASTER THAN CASING DUE TO MASS DIFFERENCE. WARM UP ENSURES THAT BOTH EXPAND PARALLELY AND CLEARANCES ARE MAINTAINED & RUBBING OF PARTS IS AVOIDED.

TG SET IS THEN ROLLED USING THE SPEED CONTROL-PI MODE. THE SPEED REFERENCE IS SELECTED AS PER THE START-UP CURVES GIVEN IN THE FOLLOWING IMAGE I.E. 500 RPM / 3000 RPM / 5000 RPM.

ROLLING, WARM UP

CRITICAL SPEED AVOIDANCE

THE EHTC SPEED CONTROL RAISES THE SPEED AT FASTER RATE IN THE CRITICAL SPEED BANDS TO MINIMIZE THE TIME OF OPERATION IN THIS ZONE. AFTER WARM UP THE SPEED REFERENCE IS SET TO RATED VALUE FOR SYNCHRONIZATION

CRITICAL SPEED BANDS1300 TO 1700 RPM2000 TO 2500 RPM

TG SET RUN AT RATED SPEED I.E. 5000 RPM

AVR VOLT CONTROL SWITCHED ON & GEN STATOR VOLT BUILT UP THRO’ AVR

TG FREQ IS VARIED BY CHANGING SPEED REF

THE FREQ, VOLT & PHASE ANGLE OF TG ARE MATCHED TO GRID BEFORE CLOSING GCB

GCB IS CLOSED. THIS SYNCHRONIZES THE TG SET WITH THE GRID

AS GCB CLOSES, THE EHTC MODE SWITCHES TO SPEED CONTROL-PD

SPEED CONTROLLER O/P INCREASES BY ABOUT 10% SO AS TO LOAD THE TG TO BLOCK LOAD OF AROUND 1-2MW SO THAT GCB DOES NOT TRIP ON LOW FORWARD POWER.

AVR MODE IS MANUALLY CHANGED FROM VOLT CONTROL TO PF CONTROL

SYNCHRONIZATION AFTER ROLLING

SPEED CONTROLLER

PI -> PD MODE

SPEED REF

5000 -> 5083

SPEED ACTUAL

5000 RPM

15% -> 25%

SPEED CONTROLLER

AFTER SYNCHRONIZATION, LOAD CONTROLLER IS SWITCHED ON

EHTC SETS THE LOAD REF TO THE RUNNING LOAD AND ITS OUTPUT IS SET TO THE VALUE OF SPEED CONTROLLER OUTPUT BY TRACKING I-ACTION

PD MODE OUTPUT

=%ERROR * GAIN

=0.16667*18=3.0

3.0%SPEED REF

(SV) 5010

SPEED ACTUAL (PV) 5000

%ERROR=((SV-PV)/

RANGE)*100((5010-5000)/

6000)*100=0.16667%

LOAD CONTROL

SPEED CONTROLLER

PD MODE

LOAD CONTROLLER

PID

P=0, D=0, as SV=PV

I-action tracks 25%

 

SPEED REF

5083

LOAD REF

2 MW

LOAD ACTUAL

2 MW

SPEED ACTUAL

5000 RPM

25%

25%

SPEED CONTROL-PD SWITCHES TO SPEED TRACKING MODE I.E. THE SPEED REF TRACKS THE ACTUAL SPEED + 10 RPM TO SET SPEED CONTROLLER OUTPUT AT 3.0% FIXED. (THE GAIN IS PRESSURE COMPENSATED AND INCREASES FROM 17 TO 22 AS MS PRESSURE REDUCES FROM 110 TO 90 ATA.)

NORMALLY TG SETS ARE IN LOAD CONTROL MODE WHEN SYNCHRONIZED WITH GRID. IF THE TIE OPENS THEN TG SET(S) ARE ISLANDED, LOAD CONTROLLER SWITCHES OFF & SPEED CONTROL-PD MODE TAKES OVER BUMPLESSLY. DURING THIS SWITCH OVER, THE SPEED REF IS CALCULATED SUCH THAT THE OUTPUT OF LOAD CONTROLLER (2S DELAYED) IS AVAILABLE AT SPEED CONTROLLER OUTPUT IN PD MODE. AFTER THIS THE LOAD CONTROLLER SWITCHES OFF & TG SET RUNS IN SPEED CONTROL-PD MODE.

 

ISLANDING

SPEED CONTROLLER

PD MODE

LOAD CONTROLLER

PID

P=0, D=0, as SV=PV

I-action tracks 25%

 

SPEED REF

5010 -> 5167

LOAD REF

20 -> 0

LOAD ACTUAL

20 MW

SPEED ACTUAL

5000 RPM

3% -> 50%

50% -> 0%

DROOPDROOP CONTROL IS REQUIRED IN SYSTEMS WHERE A COMMON PARAMETER IS CONTROLLED BY 2 OR MORE SYSTEMS.

E.G. FREQ OR VOLT CONTROL IN CASE OF 2 OR MORE SYNCHRONIZED TG SETS.

COMMON HEADER PRESSURE CONTROL IN CASE OF 2 OR MORE BOILERS.

IF A COMMON PARAMETER IS SENSED BY TWO OR MORE SENSORS, THE READINGS CANNOT MATCH EXACTLY. THERE WILL ALWASYS BE SOME DIFFERENCE EVEN THOUGH IT MAY BE VERY SMALL. IF BOTH SENSORS PROVIDE PV TO TWO DIFFEENT PID CONTROLLERS THEN THEY WILL TEND TO SATURATE IN OPPOSITE DIRECTIONS.

E.G. CONSIDER A CASE OF TWO TG SETS “L” & “H” RUNNING IN SYNCHRONIZED CONDITION. LET BOTH TG GOVERNORS BE SET TO ISOCHRONOUS FREQ CONTROL I.E. SPEED PID CONTROL. LET REF OF BOTH TG BE SET AT 50.00HZ.

LET THE ACTUAL SYSTEM BUS FREQ BE 50.00HZ, AND ONE SENSOR SENSES L=49.99 & OTHER H=50.01.

THE INTEGRAL ACTION OF L WILL INCREASE OUTPUT AND H WILL DECREASE OUTPUT TO BRING FREQ TO 50.00. THIS PROCESS WILL CONTINUE AS THERE WILL ALWAYS BE OFFSET IN THE READINGS OF L & H, SO GRADUALLY L OUTPUT WILL SATURATE TO 100% AND H OUTPUT WILL SATURATE TO 0%.

SO EITHER THE INTEGRAL ACTION IS REMOVED I.E PD ACTION SELECTED OR REF IS CHANGED AS PER CONTROLLER OUTPUT TO INSERT DROOP OR OFFSET IN THE CONTROL ACTION I.E. REF & PV ARE NOT MATCHED.

DROOP

% DROOP MEANS % CHANGE IN FREQ FOR 100 % CHANGE IN LOAD.4% DROOP IMPLIES 4% FREQ CHANGE WILL CAUSE 100% CHANGE IN LOAD. i.e. GAIN=100/4=25%

DROOPFREQHz

LOAD MW320

50.0

2711

51.5

DROOP = % CHANGE IN FREQ FOR 100 % CHANGE IN LOAD = (3/50)*100 = 6%GAIN = 100/DROOP = 16.7LOAD ON TG IS REDUCED FROM 27MW TO 11MW I.E. 16MW OR 50% LOAD THROWSO GOVERNOR OUPUT SHOULD REDUCE by 50% I.E. FROM 81.4% TO 34.4% FOR STABLE FREQ(IN TG SPEED CONTROL THE GOV VLV OPENING SHOULD EXACTLY MATCH THE LOAD ELSE SPEED WILL KEEP ON RAMPING. THIS IS KNOWN AS INTEGRATING TYPE OF PROCESS.) THE 34.4% O/P IS REQUIRED AT 11MW LOAD TO KEEP FREQ STABLE. BUT 34.4% O/P IS AVAILABLE AT 51.5HZ FREQ. THIS OFFSET IS RESET BY MANUALLY DECREASING THE SPEED REF (SV) SO THAT 34.4% O/P IS AVAILABLE AT 50HZ.

1.5 Hz = 3%

27-11= 16MW=50% 10

00 84.

434.4

GOV O/P %

84.4%

SPEED CONTROLLERPD MODE OUTPUT

=%ERROR * GAIN

%ERROR=((SV-PV)/

RANGE)*100

O/P %

SPEED CONTROLLER

=5.05*16.7=84.4

((5253-5000)/5000)*100

=5.05%

34.4%SPEED CONTROLLER

=2.06*16.7=34.4

((5253-5150)/5000)*100

=2.06%

SPEED REF SVSPEED ACTUAL

PV

5253

5000

5253

5150

34.4%SPEED CONTROLLER

=2.06*16.7=34.4

((5103-5000)/5000)*100

=2.06%

5103

5000

DROOP

ISOCHRONOUS FREQ CONTROL

CONSIDER FOLL SEQUENCE OF EVENTS:

THREE TG SETS LOADED AT 27MW EACH, GRID AT 15MW I.E. TOTAL LOAD 96MW

CHEMICAL DIV. TRIPS (70MW LOAD THROW), BALANCE LOAD IS 96MW-70MW=26MW

GRID TRIPS (15MW) ON REV POWER

THE 3 TG SETS ARE ISLANDED IN DROOP MODE (DROOP=6%), CONNECTED LOAD = 26MW, I.E. 8.67MW PER TG

SO, FOR EACH TG SET % LOAD REDUCTION = [(27 - 8.67)/32]*100 = 57.28%THE GOV O/P CHANGE = (%FREQ ERROR)*(GAIN)

So, % FREQ ERROR = 57.28/16.7 = 3.43% I.E. 3.43/2 = 1.7HZ

SO FINAL FREQ WILL STABILIZE AT 51.7HZ, WHICH WILL TRIP ALL TG SETS ON OVERFREQ

IF ONE TG IS IN ISOCHRONOUS FREQ CONTROL IN ISLAND MODE, THEN THIS TG SET WILL TRIP AFTER FULLY UNLOADING & ONLY 2 TG SETS WITH DROOP WILL RUN I.E. 13MW PER TG SET

SO, FOR EACH TG SET % LOAD REDUCTION = [(27 - 13)/32]*100 = 57.28%THE GOV O/P CHANGE = (%FREQ ERROR)*(GAIN)

So, % FREQ ERROR = 57.28/16.7 = 3.43% I.E. 3.43/2 = 1.7HZ

ISO FREQ CONTROL MODE IS PRESELECTED WHILE TG RUNNING IN LOAD CONTROL MODE, SO THAT DURING ISLANDING, THE ISO FREQ CONTROL MODE WILL BECOME ACTIVE. AT PRESENT, ONE TG IS SELECTED FOR ISO & OTHER TWO FOR SPEED CONTROL-PD MODE (DROOP).

SO ON ISLANDING, THE THREE TG SETS ARE ISLANDED WITH ONE IN ISO MODE & OTHER TWO IN DROOP MODE. IF DURING OR AFTER ISLANDING LOAD IS ADDED OR REMOVED, THEN SYSTEM FREQ WILL CHANGE, BUT THE TURBINE ON FREQ CONTROL MODE WILL KEEP ON CHANGING OUPUT TILL THE SYSTEM FREQ RETURNS TO 50HZ. THUS SYSTEM FREQ IS MAINTAINED.

TWO OR MORE TG SETS IN A SYNCHRONIZED SYSTEM CANNOT BE PUT IN ISOCHRONOUS MODE AT THE SAME TIME, AS ONE TG SET WILL LOAD FULLY & OTHER WILL FULLY UNLOAD DEPENDING ON MINOR DIFFERENCES IN SPEED/FREQ SENSORS OF THE TWO TG SETS. THEREBY DROOP MODE IS REQUIRED.

ISOCHRONOUS FREQ CONTROL

LOAD CONTROLLER

PID

 

LOAD REF25MW

LOAD ACTUAL20MW ISOCHRONOUS

FREQ CONTROLLER

PIDFREQ REF50HZ

FREQ ACTUAL50HZ

ISOCHRONOUS FREQ CONTROL

LOAD CONTROLTG SYNCHRONIZED WITH GRID

ISOCHRONOUS FREQ CONTROL

TG ISLANDED

LOAD REF20MW

LOAD ACTUAL20MW

FREQ REF50HZ

FREQ ACTUAL51HZ

ISLANDING

LOAD SHEDDING LOGICIF TIE/GRID BREAKER TRIPS, & PRO RATA LOAD ON GRID IS NOT SHED THEN THE BALANCE TG SETS MAY TRIP ON UNDER-FREQUENCY.

IF A TG SET TRIPS, ITS LOAD SHIFTS TO GRID, & TIE BREAKER TRIPS IF IMPORT EXCEEDS 20MVA (CONTRACT DEMAND LIMITATION). AFTER ISLANDING THE ENTIRE LOAD OF (GRID+TRIPPED TG) SHIFTS TO BALANCE TG SETS WHICH RESULTS IN UNDER-FREQ TRIPPING OF BALANCE TG SETS & BLACKOUT. SO, PROPORTIONATE LOAD IS TO BE SHED TO PREVENT BALANCE TG SETS FROM TRIPPING ON UNDER-FREQUENCY.

THE RECTIFORMER NOS. 1,2,3,4 ARE SHED FROM DCS AS PART OF LOAD SHEDDING LOGIC. THE PROPORTIONAL LOAD IS SHED WITHIN 400MS THROUGH DCS.

G125MW

G225MW

G325MW

GRID15MW

CD60MWVSF

25MWCPP5MW

TOTAL LOAD=90MW

G125MW

G225MW

G325MW

GRID45MW

VSF25MW

CPP5MW

TOTAL LOAD=30MW

EXPORT=45MW

TG GEN=75MW

TG GEN=75MW

IMPORT=15MW

G125MW

G225MW

GRID40MW

CD60MWVSF

25MWCPP5MW

TOTAL LOAD=90MW

TG GEN=50MWIMPORT=40MW

CASE1: TG TRIP CASE2: LOAD THROW

RATIO SETTER

Exhaust flow

HP CV OPN

HP CV CLS

EXT CV OPN

EXT CV CLS

RATIO SETTER

TO CALCULATE THE TURBINE INTERNAL PRESSURE RATIOS AND LIMITS,THE INTERSECTION POINTS NEEDED ARE A,B,C

A: MAX POWER @ MIN EXTRACTIONB: MIN POWER @ MAX EXTRACTIONC: MIN HP FLOW @ MIN EXTRACTION

THE TURBINE SPEED/LOAD & EXTRACTION PRESSURE NEED TO BE MAINTAINED AT CONSTANT LEVELS SIMULTANEOUSLY. CHANGING THE POSITION OF EITHER THE HP, IP OR LP VALVE AFFECTS BOTH TURBINE SPEED/LOAD AND EXTRACTION PRESSURE. SO, TO CHANGE SPEED/LOAD ALL VALVES NEED TO BE ADJUSTED SO THAT ONLY THE SPEED/LOAD IS AFFECTED WITH MIN. OR NO DISTURBANCE TO THE EXTRACTION PRESSURES. SIMILARLY WHILE CHANGING IP EXTRACTION PRESSURE THE SPEED/LOAD OR THE LP EXTRACTION SHOULD NOT BE DISTURBED. RATIO SETTER CALCULATES THE OUTPUTS TO MINIMIZE THE CONTROLLED PARAMETERS INTERACTIONS EFFECTING EACH OTHER, AND TO KEEP THE ACTUATOR OUTPUTS WITHIN THE BOUNDARIES OF TURBINE STEAM MAP OR ENVELOPE CURVE.

RATIO SETTER

S.N. EXTR-1 CONTROL O/P (YE1)

EXTR-2 CONTROL O/P(YE2)

SPEED CONTROL GAIN

RATIO SETTER GAIN FOR SPEED/LOAD CONTROL O/P (YN)

EFFECTIVE GAIN

1 0 0 8 1.2 9.62 1 1 8 7.5 60

THE RATIO SETTER DETAILS WERE OBTAINED FROM BHEL-HYD & FOUND THAT GAIN WAS THROUGHOUT LINEAR FOR ALL THREE CONTROLLER OUTPUTS I.E. YN, YE1 & YE2.

FOR, YN (LOAD/SPEED CONTROLLER O/P) THE GAIN WAS THROUGHOUT LINEAR AT 0.632.

THE SNAPSHOTS WERE SENT TO BHEL-HYD FOR CONFIRMATION AND FOUND THAT WRONG RATIO SETTER WAS INSTALLED IN ALL THREE TG SET CONTROLLERS BY BHEL-EDN.

RATIO SETTER RELATED ISSUES

THE ORIGINAL RATIO SETTER IMPLEMENTED BY BHEL-EDN WAS FAULTY WITH NON-LINEAR GAIN AS GIVEN IN THE BELOW TABLE.

TURBINE GOVERNING SYSTEM RELATED ISSUES PERTAINING TO ISLAND CONDITION:IN ISLAND CONDITION, SPEED TRANSIENT OVERSHOOT, SPEED HUNTING & STABILITY ISSUES WERE PERSISTING.

FOLLOWING MAJOR CHANGES WERE IMPLEMENTED:

1) THE RATIO SETTER GAIN FOR HPCV OUTPUT WAS FOUND TO BE VARYING FROM “9” TO “59” DEPENDING ON THE EXTRACTION CONTROLLER OUTPUTS. RATIO SETTER FROM BHEL-HYD WITH FIXED GAIN & LINEAR CHARACTERISTIC WAS IMPLEMENTED. TRANSFER FUNCTION WAS OBTAINED FROM BHEL-HYD & THE SPEED CONTROLLER P-GAIN VALUE CHANGED FROM “8” TO “18”.

2) DURING ISLANDING THE HP & IP EXTRACTION CONTROLLERS SWITCH OVER TO MANUAL MODE TO PREVENT EXTRACTION LOOP INTERACTIONS FROM DISTURBING THE SPEED CONTROLLER & REDUCE THE TRANSIENT SETTLING TIME. AFTER STEADY STATE ACHIEVED, OPERATOR CAN SWITCH THE CONTROLLERS TO AUTO.

3) IN MAIN DCS, LOAD SHEDDING SCHEME IMPLEMENTED BY SHEDDING THE PRIORITY BASED PRO-RATA LOADS OF THE RECTIFORMER NOS. 1-4.

4) FREQUENCY CONTROL MODE OR ISOCHRONOUS MODE WAS IMPLEMENTED SO THAT THE SYSTEM FREQUENCY RETURNS TO 50 HZ AT STEADY STATE AFTER A DISTURBANCE IN ISLANDING CONDITION.

K = SYSTEM GAIN = 100/(% STEADY STATE SPEED REGULATION) = 100/5 = 20T1 = GOVERNOR TIME CONSTANT = 0.02-0.1ST2 = DERIVATIVE GAIN X GOVERNOR TIME CONST = 0.1ST3 = CONTROL VALVE ACTUATOR TIME CONST = 0.1SPUP = CV OPEN = 1 PU PER SPDOWN = CV CLOSE = 2.5 PU PER SPMIN = MIN POWER LIMITPMAX = MAX POWER LIMITPGV = POWER AT VALVE OUTLETS = COMPLEX FREQ VARIABLE (LAPLACE TRANSFORM)

FHP = HP TURBINE POWER FRACTION = 0.505FIP = IP TURBINE POWER FRACTION = 0.256FLP = LP TURBINE POWER FRACTION = 0.239THP = HP TURBINE TIME CONST = 0.115STIP = IP TURBINE TIME CONST = 0.122STLP = LP TURBINE TIME CONST = 0.125SDW = SPEED DEVIATIONPM = MECH POWERP0 = INITIAL POWERPGV = POWER AT VALVE OUTLET

BEFORE SYNCHRONIZING AN INCOMING UNIT TO A RUNNING SYSTEM, THE FOLLOWING PARAMETERS SHOULD BE MATCHED CLOSELY SO TO MINIMIZE TRANSFER OF ENERGY •VOLTAGE•FREQUENCY•PHASE ANGLE •PHASE SEQUENCETHE CIRCUIT BREAKER IS CLOSED TO TIE THE “INCOMING” SYSTEM TO THE “RUNNING” SYSTEM ELECTRICALLY

GENERATOR

DC CURRENT IS FED TO FIELD WINDING IN ROTOR TO CREATE MAGNETIC FIELD

THIS ROTATING MAGNETIC FIELD INDUCES VOLTAGE IN THE STATOR ARMATURE WINDING

THE DC CURRENT TO THE ROTOR FIELD WINDING IS CALLED FIELD CURRENT.

BY CHANGING FIELD CURRENT, THE MAGNETIC FIELD STRENGTH IS VARIED TO CHANGE STATOR TERMINAL VOLTAGE.

RPM=120*(f/P) f = frequency (Hz) P = total number of poles

G1100MW

100MW

LOAD SIDEPF=COSΦ=0.8

ACTIVE POWER=VI.COSΦ=100MWTOTAL POWER=VI=125MVA

SO REACTIVE POWER = 25MVAr

BOTH ACTIVE PWR 100MW & REACTIVE PWR 25MVAr SUPPLIED BY G1 .

AVR MODE = VOLT CONTROL

G150MW

100MW

G1 ACTIVE PWR CONTROL BY STEAM FLOW CONTROL G1 REACTIVE PWR CONTROL BY EXCITATION CONTROL AVR MODE = PF CONTROL OR REACTIVE PWR CONTROL

G1 OVEREXCITED => PF LEADING => REACTIVE PWR OUT .

G1 UNDEREXCITED => PF LAGGING => REACTIVE PWR IN I.E. EVEN REACTIVE AMPERES REQUIRED BY G1 ARE SUPPLIED BY GRID

GRID50MW

PF=0.825MVAr

PF=0.8

PF=0.8

PF=0.95.5MVAr

PF=0.7219.5MVAr

CAPABILITY CURVE

REGION A-B: LAGGING POWER FACTOR •GENERATOR IS OVER-EXCITED I.E. MORE FIELD CURRENT•CAPABILITY LIMITATION IS FIELD OVERHEATING •REGION B-C: RATED POWER FACTOR•CAPABILITY LIMITATION IS DEPENDENT ON THE STATOR CURRENT •MAXIMUM GENERATOR NAMEPLATE STATOR AMPERES SHOULD NOT BE EXCEEDED

REGION C-D: LEADING POWER FACTOR •CAPABILITY LIMITATION DUE TO EXCESSIVE HEATING IN THE STATOR IRON CORE DUE TO FLUX LEAKAGE •THIS IS ALSO AN UNDEREXCITATION REGION & CAPABILITY IS FURTHER REDUCED BY THE VOLTAGE SQUARED DURING REDUCED TERMINAL VOLTAGE OPERATION

LOAD ANGLE

AT ZERO LOAD, FIELD POLE OF ROTOR IS “IN PHASE” WITH STATOR FIELD, SO POWER ANGLE IS 0

AS LOAD ADDED , ROTOR ADVANCES WITH RESPECT TO THE STATOR, THE LOAD ANGLE INCREASES.

LOAD ANGLE ALSO INCREASES WITH UNDEREXCITATION AND MAY RESULT IN ROTOR GETTING OUT OF SYNCHRONISM WITH NETWORK FREQ IF ROTOR STABILITY LIMIT IS TRANSGRESSED

THANK YOU