ROLLING WARM UP CRITICAL SPEED AVOIDANCE LOAD / SPEED CONTROL EXTRACTION PRESSURE CONTROL ISLANDING

1. PRESENTATION ON ELECTRO
HYDRAULIC CONTROL SYSTEM
 By
 Ashvani Shukla
 C&I
 Reliance

2. 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

3. R
A
T
I
O
S
E
T
T
E
R
M
A
X
M
I
N
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
M
I
N
EXTRACTION-1 PRESSURE
LIMITER
LIMIT REF
EXTRACTION-2
PRESSURE
CONTROLLER
PRESSURE REF
PRESSURE
ACTUAL
M
I
N
EXTRACTION-2 PRESSURE
LIMITER
LIMIT REF
VALVE
CHARACTERISTIC
COMPENSATOR
HPCV LIFT REFERENCE
IPCV LIFT REFERENCE
LPCV LIFT REFERENCE
FREQ REF
FREQ ACTUAL
EHTC BLOCK DIAGRAM

4. EHTC FUNCTIONS
ROLLING
WARM UP
CRITICAL SPEED AVOIDANCE
LOAD / SPEED CONTROL
EXTRACTION PRESSURE
CONTROL
ISLANDING

5. 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 HOURS
2. WARM START: AFTER 40 HOURS
3. 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

7. 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 BANDS
1300 TO 1700 RPM
2000 TO 2500 RPM

8. 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%

9. 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.)

10. 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%

11. DROOP
DROOP 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.

12. 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%

13. DROOP
FRE
Q
Hz
LOAD
MW320
50.0
2711
51.5
DROOP = % CHANGE IN FREQ FOR 100 % CHANGE IN LOAD = (3/50)*100 = 6%
GAIN = 100/DROOP = 16.7
LOAD ON TG IS REDUCED FROM 27MW TO 11MW I.E. 16MW OR 50% LOAD THROW
SO 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
1.5 Hz = 3%
27-11
= 16MW
=50%
10
0
0 84.
4
34.4 GOV O/P
%
84.4%
SPEED CONTROLLER
PD 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 SV
SPEED
ACTUAL PV
5253
5000
5253
5150
34.4%
SPEED CONTROLLER
=2.06*16.7=34.4
((5103-
5000)/5000)*100
=2.06%
5103
5000

14. DROOP

15. 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

16. 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

17. LOAD
CONTROLLER
PID
LOAD REF
25MW
LOAD ACTUAL
20MW ISOCHRONOUS
FREQ
CONTROLLER
PIDFREQ REF
50HZ
FREQ ACTUAL
50HZ
ISOCHRONOUS FREQ CONTROL
LOAD CONTROL
TG SYNCHRONIZED WITH GRID
ISOCHRONOUS FREQ
CONTROL
TG ISLANDED
LOAD REF
20MW
LOAD
ACTUAL
20MW
FREQ REF
50HZ
FREQ ACTUAL
51HZ
ISLANDI
NG

18. LOAD SHEDDING LOGIC
IF 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.

19. G1
25MW
G2
25MW
G3
25MW
GRID
15MW
CD
60MWVSF
25MW
CPP
5MW
TOTAL LOAD=90MW
G1
25MW
G2
25MW
G3
25MW
GRID
45MW
VSF
25MW
CPP
5MW
TOTAL LOAD=30MW
EXPORT=45MW
TG GEN=75MW
TG GEN=75MW
IMPORT=15MW
G1
25MW
G2
25MW
GRID
40MW
CD
60MWVSF
25MW
CPP
5MW
TOTAL LOAD=90MW
TG GEN=50MWIMPORT=40MW
CASE1: TG TRIP CASE2: LOAD THROW

20. RATIO SETTER

21. Exhaust flow
HP CV OPN
HP CV CLS
EXT CV
OPN
EXT CV
CLS
RATIO SETTER

22. TO CALCULATE THE TURBINE INTERNAL PRESSURE RATIOS AND LIMITS,THE
INTERSECTION POINTS NEEDED ARE A,B,C
A: MAX POWER @ MIN EXTRACTION
B: MIN POWER @ MAX EXTRACTION
C: 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

25. 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 9.6
2 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.

26. 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.

27. K = SYSTEM GAIN = 100/(% STEADY STATE SPEED REGULATION) = 100/5 = 20
T1 = GOVERNOR TIME CONSTANT = 0.02-0.1S
T2 = DERIVATIVE GAIN X GOVERNOR TIME CONST = 0.1S
T3 = CONTROL VALVE ACTUATOR TIME CONST = 0.1S
PUP = CV OPEN = 1 PU PER S
PDOWN = CV CLOSE = 2.5 PU PER S
PMIN = MIN POWER LIMIT
PMAX = MAX POWER LIMIT
PGV = POWER AT VALVE OUTLET
S = COMPLEX FREQ VARIABLE (LAPLACE TRANSFORM)

28. FHP = HP TURBINE POWER FRACTION = 0.505
FIP = IP TURBINE POWER FRACTION = 0.256
FLP = LP TURBINE POWER FRACTION = 0.239
THP = HP TURBINE TIME CONST = 0.115S
TIP = IP TURBINE TIME CONST = 0.122S
TLP = LP TURBINE TIME CONST = 0.125S
DW = SPEED DEVIATION
PM = MECH POWER
P0 = INITIAL POWER
PGV = POWER AT VALVE OUTLET

31. 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 SEQUENCE
THE CIRCUIT BREAKER IS CLOSED TO TIE THE “INCOMING” SYSTEM TO THE
“RUNNING” SYSTEM ELECTRICALLY

32. GENERAT
OR
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.

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

34. G1
100
MW
100
MW
LOAD SIDE
PF=COSΦ=0.8
ACTIVE POWER=VI.COSΦ=100MW
TOTAL POWER=VI=125MVA
SO REACTIVE POWER = 25MVAr
BOTH ACTIVE PWR 100MW &
REACTIVE PWR 25MVAr
SUPPLIED BY G1 .
AVR MODE = VOLT CONTROL
G1
50
MW
100
MW
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
GRID
50MW
PF=0.8
25MVAr
PF=0.
8
PF=0.
8
PF=0.9
5.5MVAr
PF=0.72
19.5MVAr

35. CAPABILITY CURVE

36. 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

37. 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

38.  THANK YOU