presentation on “free governor mode operation”
DESCRIPTION
Presentation on “FREE GOVERNOR MODE OPERATION”. FREE GOVERNOR OPERATION. FREQ COMPARISION MAY-02 & MAY-03. ROLE. ABT & GOVERNOR. WHY. BEFORE GOVERNOR. GOVERNOR RESPONSE IN NER. BLOCKED GOVERNOR. CHARACTERISTICS. GOVERNOR. GOVERNOR TYPES. GOVERNOR TIME LAG. DEAD BAND. TIME DELAY. - PowerPoint PPT PresentationTRANSCRIPT
Presentation on Presentation on ““FREE GOVERNOR MODE OPERATION”FREE GOVERNOR MODE OPERATION”
FREE GOVERNOR OPERATION
WHYFREQ COMPARISION
MAY-02 & MAY-03
GOVERNOR
BEFORE GOVERNOR GOVERNOR RESPONSEIN NER
DEAD BAND GOVERNOR TIME LAG
BLOCKED GOVERNOR
ROLE
DROOPFREQUENCY DECAY RATEBACKLASH
TYPES OF CONTROLSDROOP RESPONSE IN SR
ABT & GOVERNOR
ADVANTAGES
GOVERNOR TYPES
TIME DELAY
CHARACTERISTICS
PROBLEMSUCPE/NERC
LIST OF GENERATORS
FREQUENCY BASED DISPATCH
FREQUENCY BASED DISPATCH
SUPPRESSED GOVERNORACTION
PID CONTROLPTI TAPE ORDERS
ORDERS
IEGC 6.2 (e) & 6.2(f)IEGC 1.6 IEGC 6.2 (g)
IEGC 6.2 (h)CERC ORDER ON
WB dt 02/01/01
KERALA LETTER ON FGM
FREE GOVERNOR OPERATION
ROLE OF SYSTEM OPERATOR
• LOAD GENERATION BALANCE
50
WHY DOES FREQUENCY DROP ?WHY DOES FREQUENCY DROP ? Sudden addition of load causes a drop in frequency.
An increased load is supplied through an increase in the load angle by which the rotor lags the stator field.
It means a loss of Kinetic Energy of the rotating M/c and a slower speed of rotation i.e. a lower frequency.
f = (P/2) X (N/60)
Where f = frequency of the system
P = no of poles of the M/c.
N = rpm of the M/c.
• Load dependent on frequency
• Free Governor Operation
• Under Frequency Operation
PRIMARY CONTROLSPRIMARY CONTROLS
PRIMARY CONTROL …… PRIMARY CONTROL …… (UCPE)(UCPE) Primary control involves the action of Primary control involves the action of
turbine speed governors in generating turbine speed governors in generating units, which will respond where the speed units, which will respond where the speed (frequency) deviates from the speed (frequency) deviates from the speed (frequency) set point as a result of an (frequency) set point as a result of an imbalance between generation and imbalance between generation and demand in the synchronously demand in the synchronously interconnected network as a whole. interconnected network as a whole. Technical solidarity between members will Technical solidarity between members will involve the simultaneous action of primary involve the simultaneous action of primary control on all generating units involved in control on all generating units involved in system control.system control.
PRIMARY CONTROL…… PRIMARY CONTROL…… (UCPE)(UCPE) The various assumptions, characteristics and The various assumptions, characteristics and
parameters applied to primary control are as parameters applied to primary control are as follows:follows:
► The maximum instantaneous deviation ∆P between The maximum instantaneous deviation ∆P between generation and demand to be corrected by primary generation and demand to be corrected by primary control is 2000 MW control is 2000 MW
► For the whole system, with a peak load of the order For the whole system, with a peak load of the order of 20000 MW and an off-peak load of the order of of 20000 MW and an off-peak load of the order of 12000 MW, assuming 1% self-regulation of load, the 12000 MW, assuming 1% self-regulation of load, the quasi-steady-state frequency deviation must not quasi-steady-state frequency deviation must not exceed 180 mHz and the instantaneous frequency exceed 180 mHz and the instantaneous frequency must not fall below 49.2 Hz in response to a must not fall below 49.2 Hz in response to a shortfall in generation capacity equal to or less than shortfall in generation capacity equal to or less than 2000 MW. The overall network power frequency 2000 MW. The overall network power frequency characteristic for the system is set at 1000 MW/Hzcharacteristic for the system is set at 1000 MW/Hz
FREQUENCY RESPONSE …… FREQUENCY RESPONSE …… (NERC)(NERC)
NERC
ABT AND GOVERNORABT AND GOVERNORPOST ABT FREQUENCY WITHIN 49 TO
50.5HZ
ACHIEVED BY STAGGERING OF LOADS
FLUCTUATION IN FREQUENCY INCREASED
FREQUENCY COMPARISON FOR
47.50
48.00
48.50
49.00
49.50
50.00
50.50
51.00
51.50
00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23
04-MARCH 02 & 03
Frequency Variation based on data integrated over ONE minute interval
2003
2002
HUMAN GOVERNOR OPERATIONHUMAN GOVERNOR OPERATION
SYSTEM~TGX
GOVERNOR
GOVERNORGOVERNOR
SPEED GOVERNOR IS THE CONTROLLING MECHANISM WHICH
CONTROLS THE INPUT TO THE PRIME MOVER AUTOMATICALLY
WHEN THERE IS A CHANGE IN SYSTEM SPEED (FREQUENCY)
WHEN THERE IS A CHANGE IN SYSTEM FREQUENCY GOVERNOR
RESPONSE BY CAUSING VALVES/GATES TO OPEN/CLOSE TO
INCREASE/DECREASE THE INPUT TO THE PRIME MOVER
MISCONCEPTIONMISCONCEPTIONGovernors attempt to restore frequency to normal.
In reality, Governors attempt to restore load generation balance, using frequency change as a signal.
CHARACTERISTICSCHARACTERISTICS1.1. Respond promptly to a small change Respond promptly to a small change
in in speed.speed.2.2. Adjust the throttle valve with a Adjust the throttle valve with a
minimum minimum of overshoot.of overshoot.3.3. Have sufficient power to overcome Have sufficient power to overcome
friction losses and unbalance forces in friction losses and unbalance forces in the throttle valve.the throttle valve.
4.4. Permit very little speed fluctuation Permit very little speed fluctuation under under constant load and steam constant load and steam
conditions.conditions.
TYPES OF GOVERNORSTYPES OF GOVERNORS►Mechanical shaftMechanical shaft►Direct acting orifice Direct acting orifice ►Oil relay Oil relay ►Precision oil relay Precision oil relay ►Electronic governorElectronic governor
DEAD BANDDEAD BANDDEAD BAND OF THE SPEED GOVERNORING SYSTEM IS THE TOTAL
AMOUNT OF CHANGE IN STEADY STATE SPEED WITHIN WHICH THERE IS NO ACTION BY GOVERNOR.
Turbine rated Turbine rated output MWoutput MW
Dead band percent of Dead band percent of rated speedrated speed
IN 50HZ BASEIN 50HZ BASE
< 5MW< 5MW 0.150.15 0.075HZ0.075HZ
5 to 30mw5 to 30mw 0.100.10 0.050HZ0.050HZ
> 30mw > 30mw 0.060.06 0.030HZ0.030HZ
IEC - 45
DROOP CHARACTERISTICSDROOP CHARACTERISTICSTHE AMOUNT OF SPEED (OR FREQUENCY) CHANGE THAT IS NECESSARY TO CAUSE THE MAIN PRIME MOVER CONTROL
MECHANISM TO MOVE FROM FULLY CLOSED TO FULLY OPEN.
NORMAL RANGE - 3 TO 5%
THE MINIMUM RATE OF CHANGE OF SPEED SHOULD NOT BE LESS THAN 0.4 TIMES OF ITS DROOP.
THE MAXIMUM RATE OF CHANGE OF SPEED SHOULD NOT BE MORE THAN 3 TIMES OF ITS DROOP.
5% DROOP ON 200MW GENERATOR
0
40
80
120
160
200
49 49.5 50 50.5 51 51.5
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
--->
PARTICIPATION OF 5% DROOP ON 200MW & 500MW GENERATORS
0
100
200
300
400
500
600
49 49.5 50 50.5 51 51.5
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
--->
100MW for 0.5HZ Frequency
40MW for 0.5HZ Frequency
GOVERNOR DROOP 5% (500MW UNIT)
0
100
200
300
400
500
600
47 47.5 48 48.5 49 49.5 50 50.5 51 51.5 52 52.5 53
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
---->
600
500
300
200
0
GOVERNOR DROOP 5% (210MW UNIT)
0
50
100
150
200
250
47 47.5 48 48.5 49 49.5 50 50.5 51 51.5 52 52.5 53
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
---->
250
210
125
85
0
RESPONSE BY A 500 MW GENERATOR WITH DIFFRENT DROOP
0
375
125
0
200
500
400
300
100
500
250
0
50
100
150
200
250
300
350
400
450
500
48 48.5 49 49.5 50 50.5 51 51.5HZ->
MW
->
5 % DROOP
4 % DROOP
GOVERNOR TIME LAGGOVERNOR TIME LAGTIME TAKEN BY GOVERNOR TO JUST BEGIN CHANGING POWER OUTPUT
TO STABILISE FREQUENCY.
OR
TIME BETWEEN A CHANGE IN GENERATOR SPEED & CHANGE IN TURBINE POWER.
• Dead band 0.25 sec
• Valve opening 0.5 sec
• Steam flow 4 seconds
• During transient state Governor is of little help.
• Effect is felt during steady state
TIME DELAY IN GOVERNOR TIME DELAY IN GOVERNOR OPERATIONOPERATION
BLOCKED GOVERNORBLOCKED GOVERNORBYPASSING THE GOVERNING FEEDBACK MECHANISM TO MAINTAIN
FIXED GENERATOR OUTPUT.
DISADVANTAGES:-
• SYSTEM INSTABILITY
• RESTORATION OF SYSTEM FREQUENCY TO NORMAL TAKES MORE TIME AFTER A DISTURBANCE.
FREQUENCY DECAY RATEFREQUENCY DECAY RATEApproximate Freq 5 X Lost Generation
Decay Rate = --------------------------------------
In Hz / sec Remaining Generation
Example:-
2200MW200MW
Generation Lost
Freq decay rate = (5 X 200) / 2000 = 0.5 Hz /second
NEYVELI U-4 ON FGM ON 19/06/2003
160
170
180
190
200
210
220
11:00 11:15 11:30 11:45 12:00 12:15 12:30 12:45 13:00
TIME ->
MW
->
49
49.2
49.4
49.6
49.8
50
50.2
50.4
HZ-
>
GENERATION
FREQUENCY
DROOP CHARACTERISTICS OF NYL U4
170
175
180
185
190
195
200
205
210
49.6 49.7 49.8 49.9 50 50.1 50.2 50.3 50.4 50.5
FREQ CHANGE 49.7 - > 50.4 0.7HzGEN CHANGE 205 -> 177 35MW CHANGE IN GEN 28 MW FOR 0.7 Hz CHANGE IN FREQFOR 200 MW CHANGE IN GEN FREQ CHANGE REQD =(200*0.7)/28 = 5 Hzi.e 5*100 /50 = 10% Droop
NLY U6 ON FGM ON 15/07/03
145
150
155
160
165
170
175
180
185
190
195
11:30 11:45 12:00 12:15 12:30
TIME-->
MW
-->
49
49.2
49.4
49.6
49.8
50
50.2
50.4
50.6
HZ
-->
GENERATION
FREQUENCY
DROOP CHARACTERISTICS OF NYL U6
160
165
170
175
180
185
190
195
49.8 49.9 50 50.1 50.2 50.3 50.4 50.5 50.6 50.7
FREQ CHANGE 49.9 - > 50.5 0.6HzGEN CHANGE 191 -> 168 23MW CHANGE IN GEN 24 MW FOR 0.6 Hz CHANGE IN FREQFOR 200 MW CHANGE IN GEN FREQ CHANGE REQD =(200*0.6)/24 = 5 Hzi.e 5*100 /50 = 10% Droop
IDUKKI GENERATION ON 16/07/2003
0
50
100
150
200
250
300
350
400
0 2 4 6 8 10 12 14 16 18 20 22 0
MW
48.5
49
49.5
50
50.5
51
FREQ
->
FREQUENCY
GENERATION
DROOP CHARACTERSTICS OF IDUKKI
0
50
100
150
200
250
300
350
400
49.3 49.4 49.5 49.6 49.7 49.8 49.9 50 50.1
49.849.1 49.749.649.549.449.2 49.3 49.9
POINT APOINT B
POINT C
POINT D
POINT A - GENERATION LOSS
POINT B – GOVERNOR ACTION STARTED
POINT C - FREQUENCY AFTER GOVERNER ACTION
POINT D – FREQUENCY AFTER OPERATOR ACTION
The distance through which one part of connected machinery, as a
wheel, piston, or screw, can be moved without moving the connected parts.
BACKLASHBACKLASH
BOILER CONTROLSBOILER CONTROLS• BOILER FOLLOWING SYSTEM
• TURBINE FOLLOWING SYSTEM
• INTEGRATED CONTROL SYSTEM
50
ADVANTAGESADVANTAGES1. Reduce the random change of frequency
2. Mitigate effect of load generation mismatch
3. Prevents wastage of fuel during low load condition
4. Faster restoration from grid disturbance
PROBLEMSPROBLEMS1.1. Steam deposits on the valve stem .Steam deposits on the valve stem .
2.2. Lubrication deposits (i.e., soaps, dirt, detergents, Lubrication deposits (i.e., soaps, dirt, detergents, etc.) in the top works of the valve exposed to the etc.) in the top works of the valve exposed to the
elements.elements.3.3. Mechanical failures of the valve resulting from Mechanical failures of the valve resulting from bent stems, either in the valve proper or the upper bent stems, either in the valve proper or the upper
works, damaged split couplings, etc., all within works, damaged split couplings, etc., all within about a 6" area near the center of the valve about a 6" area near the center of the valve
mechanism.mechanism.4.4. Galling of the piston in the hydraulic latch cylinder.Galling of the piston in the hydraulic latch cylinder.
5.5. Jamming of the screw spindle in the larger Jamming of the screw spindle in the larger cylinder-type valve design due to forcing by cylinder-type valve design due to forcing by
operations personneloperations personnel
FREE GOVERNOR OPERATIONFREE GOVERNOR OPERATIONMother of all Controls
Self healing mechanism
Collectively Control
Most equitable
Reduces risk of collapse
Makes restoration easy
World wide mandatory practice
5% DROOP OF 210MW UNIT OF STATION AVARIABLE COST = 140 Ps
140
150
160
170
180
190
200
210
49 49.1 49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50 50.1 50.2 50.3 50.4 50.5
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
--->
0
60
120
180
240
300
360
420
UI P
RIC
E -->
STEADY STATE OPERATION
AT 50 HZ GEN= 190MW
5% DROOP OF 210MW UNIT OF STATION AVARIABLE COST = 140 Ps
140
150
160
170
180
190
200
210
49 49.1 49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50 50.1 50.2 50.3 50.4 50.5
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
--->
0
60
120
180
240
300
360
420
UI P
RIC
E -->
OVER GENERATED BY 5%
FREQUENCY DIPPED TO 49.8 HZ
GENERATION INCREASED BY 10 MW
5% DROOP OF 210MW UNIT OF STATION AVARIABLE COST = 140 Ps
140
150
160
170
180
190
200
210
49 49.1 49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50 50.1 50.2 50.3 50.4 50.5
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
--->
0
60
120
180
240
300
360
420
UI P
RIC
E -->
OVER GENERATED BY 5%
5% DROOP OF 210MW UNIT OF STATION AVARIABLE COST = 140 Ps
140
150
160
170
180
190
200
210
49 49.1 49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50 50.1 50.2 50.3 50.4 50.5
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
--->
0
60
120
180
240
300
360
420
UI P
RIC
E -->
STEADY STATE OPERATION
AT 50 HZ GEN= 190MW
5% DROOP OF 210MW UNIT OF STATION AVARIABLE COST = 140 Ps
140
150
160
170
180
190
200
210
49 49.1 49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50 50.1 50.2 50.3 50.4 50.5
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
--->
0
60
120
180
240
300
360
420
UI P
RIC
E -->
UI PRICE = 84 Ps
FREQUENCY RISE UPTO 50.2 HZ
GENERATION DECREASED BY 17MW
INITIAL
5% DROOP OF 210MW UNIT OF STATION BVARIABLE COST = 70 Ps
140
150
160
170
180
190
200
210
49 49.1 49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50 50.1 50.2 50.3 50.4 50.5
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
--->
0
60
120
180
240
300
360
420
UI P
RIC
E -->
UI PRICE = 84 Ps
FREQUENCY RISE UPTO 50.2 HZ
GENERATION DECREASED BY 17MW
INITIAL
5% DROOP OF 210MW UNIT OF STATION BVARIABLE COST = 70 Ps
140
150
160
170
180
190
200
210
49 49.1 49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50 50.1 50.2 50.3 50.4 50.5
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
--->
0
60
120
180
240
300
360
420
UI P
RIC
E -->
GENERATION INCREASED BY 17MW
FINALSINCE VARIABLE COST OF
STATION B < UI PRICE
5% DROOP OF 210MW UNIT OF STATION AVARIABLE COST = 140 Ps
140
150
160
170
180
190
200
210
49 49.1 49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50 50.1 50.2 50.3 50.4 50.5
FREQ IN HZ --->
GEN
ERA
TIO
N IN
MW
--->
0
60
120
180
240
300
360
420
UI P
RIC
E -->
FINAL
GENERATION FURTHER REDUCED BY 17MW
SINCE VARIABLE COST OF
STATION A > UI PRICE
Kc∑
FB
PROPORTIONAL CONTROL
A simple form of control, where the controller response is proportional to the control error.
Provides immediate controller response to setpoint change, but speed may not settle exactly on SP using proportional control alone
∑
FB
∫ fdt1/Tc
INTEGRAL CONTROL
Control action is control error integrated over time.
–Integrates the error over time to overcome the offset from Proportional alone such that speed = SP. However, Integral action may cause overshoot, oscillation and/or instability problems
Kc
PID Parameter Tuning – PI only
∑
FB
df/dtTd
DIFFERENTIAL CONTROLIn differential control, control action is based on the change (derivative) of the control error.
Used to put the reigns on PI control to prevent overshoot and oscillation and to add stability
Kc
A form of control based on the three basic types of control: proportional, integral and differential control. PID Controllers are created by combining P, I and D elements to get the desired control characteristic.
PID CONTROL
SUPPRESSED GOVERNOR OPERATION
OPEN
1.6 Free-Governor Action:The dates from which the stipulations under sections 4.8(c), 4.8(d), 6.2(e), 6.2(f),
6.2(g) and 6.2(h) would come into effect shall be as under : (i) All thermal generating units of installed capacity 200 MW and above and reservoir based hydro units of installed capacity 50 MW and above :
Southern Region } }
Eastern Region } }
Northern Region } The date for the } implementation of the
Western Region } Commercial mechanism} mentioned in Section 7.1(d)
(ii) All thermal and reservoir based hydro } for the respective region. generating units of installed capacity } 10 MW and above in North Eastern Region } (iii) All other generating units - three months after the above dates for the respective regions except in the case of Nuclear Power Stations which shall be exempted till the next review of the IEGC.
Any exemption from the above may be granted only by CERC for which the concerned constituent shall file a petition in advance.
CERC ORDER ON ‘IEGC’ DATED 22.02.2002QUOTE
UNQUOTE
6.2(e) All generating units, which are synchronised with the grid, irrespective of
their ownership, type and size, shall have their governors in normal operation at all
times. If any generating unit of over fifty (50) MW size (10 MW for North Eastern
Region) is required to be operated without its governor in normal operation, the
RLDC shall be immediately advised about the reason and duration of such
operation. All governors shall have a droop of between 3% and 6%.
6.2(f) Facilities available with/in load limiters, Automatic Turbine Run up System
(ATRS), Turbine supervisory control, coordinated control system, etc. shall not be
used to suppress the normal governor action in any manner. No dead bands and/or
time delays shall be deliberately introduced.
CERC ORDER ON ‘IEGC’ DATED 22.02.2002QUOTE
UNQUOTE
6.2(g) All Generating Units, operating at/up to 100% of their Maximum Continuous
Rating (MCR) shall normally be capable of (and shall not in any way be prevented from)
instantaneously picking up five per cent (5%) extra load for at least five (5) minutes or
within technical limits prescribed by the manufacturer when frequency falls due to a
system contingency. The generating units operating at above 100% of their MCR shall
be capable of (and shall not be prevented from) going at least up to 105% of their MCR
when frequency falls suddenly. Any generating unit of over fifty (50) MW size (10 MW for
NER) not complying with the above requirement, shall be kept in operation
(synchronised with the Regional grid) only after obtaining the permission of RLDC.
However, the constituent can make up the corresponding short fall in spinning reserve
by maintaining an extra spinning reserve on the other generating units of the constituent.
CERC ORDER ON ‘IEGC’ DATED 22.02.2002QUOTE
UNQUOTE
6.2(h) The recommended rate for changing the governor setting, i.e. supplementary
control for increasing or decreasing the output (generation level) for all generating .units,
irrespective of their type and size, would be one (1.0) per cent per minute or as per
manufacturer's limits. However, if frequency falls below 49.5 Hz, all partly loaded
generating units shall pick up additional load at a faster rate, according to their capability.
CERC ORDER ON ‘IEGC’ DATED 22.02.2002QUOTE
UNQUOTE
FREE GOVERNOR MODE OF OPERATION
Quote
6.2 (c) All generating units, which are synchronised with the grid, irrespective of their ownership, type and size, shall have
their governors in normal operation at all times. If any generating unit of over fifty (50) MW size (10 MW for North
Eastern Region) is required to be operated without its governor in normal operation, the RLDC shall be immediately advised
about the reason and duration of such operation. All governors shall have a droop of between 3% and 6%.
Unquote
CERC Order ON ‘IEGC’ dated 21.12.1999
SRLDC Requested all constituents including ISGS vide letter dated 3rd Jan 03 to take a lead in this matter.
FREE GOVERNOR MODE OF OPERATION• The matter discussed in 368th OCC meeting
• All SR constituents/ISGS agreed to convey their readiness by 21.01.2003
• SRLDC again requested all constituents vide letter dt.21.01.03 to intimate unit/station wise status/ programme
• Matter discussed in 109th TCC/131st SREB meeting.
• ISGS/SR constituents agreed for FGM by 1st May 2003.• Discussed in 369th, 370th, 371st & 372nd OCC meetings.• KSEB & TNEB furnished unit wise/ station wise program/ constraint/ preparedness• APTRANSCO conveyed readiness for FGM of all generators except thermal units of APGENCO• Freq response characteristics calculation details covering 3 events furnished for examination & necessary
feedback by the constituents.• Constituents Actual response Shortfall
(AVG) (AVG)
AP 2 % 98 % KAR 17 % 83 % KER 29 % 71 % TN 13 % 87 %
• Matter again discussed in 110th TCC/132nd SREB meeting.• All SR constituents/ISGS agreed for FGM by 1st August 2003.• Action by constituents to achieve the target to be discussed.• Present status to be reviewed.
NLY-II U#4LETTERS
NEYVELI U-4 ON FGM ON 19/06/2003
160
170
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220
11:00 11:15 11:30 11:45 12:00 12:15 12:30 12:45 13:0049
49.2
49.4
49.6
49.8
50
50.2
50.4
NYL U-4 GENERATION
REDUCTION OF 21 MW IN 5 MTS
FREQUENCY
Thank you