Transcript FREE GOVERNOR OPERATION

Presentation on
“FREE GOVERNOR MODE OPERATION”
FREE GOVERNOR OPERATION
ROLE
WHY
FREQ
ABT COMPARISION
& GOVERNOR
MAY-02 & MAY-03
BEFORE GOVERNOR
BLOCKED GOVERNOR
GOVERNOR RESPONSE
IN NER
GOVERNOR
CHARACTERISTICS
GOVERNOR TYPES
DEAD BAND
GOVERNOR TIME LAG
FREQUENCY DECAY RATE
TIME DELAY
BACKLASH
DROOP
TYPES OF CONTROLS
DROOP RESPONSE IN SR
ADVANTAGES
UCPE/NERC
PROBLEMS
FREQUENCY BASED
DISPATCH
PID CONTROL
LIST OF GENERATORS
FREQUENCY BASED
DISPATCH
SUPPRESSED GOVERNOR
ACTION
PTI TAPE
ORDERS
ORDERS
IEGC 1.6
IEGC 6.2 (h)
IEGC 6.2 (e) & 6.2(f)
CERC ORDER ON
WB dt 02/01/01
KERALA LETTER
ON FGM
IEGC 6.2 (g)
FREE GOVERNOR
OPERATION
ROLE OF SYSTEM OPERATOR
• LOAD GENERATION
BALANCE
50
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.
PRIMARY CONTROLS
• Load dependent on frequency
• Free Governor Operation
• Under Frequency Operation
PRIMARY CONTROL …… (UCPE)
Primary control involves the action of
turbine speed governors in generating units,
which will respond where the speed
(frequency) deviates from the speed
(frequency) set point as a result of an
imbalance between generation and demand
in the synchronously interconnected
network as a whole. Technical solidarity
between members will involve the
simultaneous action of primary control on all
generating units involved in system control.
PRIMARY CONTROL…… (UCPE)
The various assumptions, characteristics and parameters
applied to primary control are as follows:
► The maximum instantaneous deviation ∆P between
generation and demand to be corrected by primary control
is 2000 MW
► For the whole system, with a peak load of the order of
20000 MW and an off-peak load of the order of 12000 MW,
assuming 1% self-regulation of load, the quasi-steadystate frequency deviation must not exceed 180 mHz and
the instantaneous frequency must not fall below 49.2 Hz in
response to a shortfall in generation capacity equal to or
less than 2000 MW. The overall network power frequency
characteristic for the system is set at 1000 MW/Hz
FREQUENCY RESPONSE …… (NERC)
NERC
ABT AND GOVERNOR
POST ABT FREQUENCY
WITHIN 49 TO 50.5HZ
ACHIEVED BY STAGGERING OF LOADS
FLUCTUATION IN FREQUENCY INCREASED
FREQUENCY COMPARISON FOR
04-MARCH 02 & 03
51.50
51.00
2003
50.50
50.00
49.50
49.00
48.50
2002
48.00
47.50
00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23
2003
2002
Frequency Variation based on data integrated over ONE minute interval
49.0 &
49.5 &
50.5 &
<49.0
Max
Min
Avg
FVI
<49.5
<50.5
Above
1.6
19.7
78.1
0.6
50.85
48.56
49.65
1.86
98.1
0.3
1.2
0.4
50.62
47.76
48.02
40.25
St. Dev
0.26
0.32
HUMAN GOVERNOR OPERATION
X
TG
GOVERNOR
~
SYSTEM
GOVERNOR
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
INCREASE/DECREASE THE INPUT TO THE PRIME MOVER
TO
MISCONCEPTION
Governors attempt to restore frequency to normal.
In reality, Governors attempt to restore load generation balance, using
frequency change as a signal.
CHARACTERISTICS
1.
Respond promptly to a small change in
speed.
2. Adjust the throttle valve with a minimum
of overshoot.
3. Have sufficient power to overcome
friction losses and unbalance forces in
the throttle valve.
4.Permit very little speed fluctuation under
constant load and steam conditions.
TYPES OF GOVERNORS
►Mechanical
shaft
►Direct acting orifice
►Oil relay
►Precision oil relay
►Electronic governor
DEAD BAND
DEAD 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 output
MW
Dead band percent of
rated speed
IN 50HZ BASE
< 5MW
0.15
0.075HZ
5 to 30mw
0.10
0.050HZ
> 30mw
0.06
0.030HZ
IEC - 45
DROOP CHARACTERISTICS
THE 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
200
GENERATION IN MW --->
160
120
80
40
0
49
49.5
50
50.5
FREQ IN HZ --->
51
51.5
PARTICIPATION OF 5% DROOP ON 200MW & 500MW GENERATORS
600
GENERATION IN MW --->
500
400
300
100MW for 0.5HZ
Frequency
200
100
40MW for 0.5HZ
Frequency
0
49
49.5
50
50.5
FREQ IN HZ --->
51
51.5
GOVERNOR DROOP 5% (500MW UNIT)
600
600
500
GENERATION IN MW ---->
500
400
300
300
200
200
100
0
0
47
47.5
48
48.5
49
49.5
50
FREQ IN HZ --->
50.5
51
51.5
52
52.5
53
GOVERNOR DROOP 5% (210MW UNIT)
250
250
210
GENERATION IN MW ---->
200
150
125
100
85
50
0
0
47
47.5
48
48.5
49
49.5
50
FREQ IN HZ --->
50.5
51
51.5
52
52.5
53
RESPONSE BY A 500 MW GENERATOR WITH DIFFRENT DROOP
500
500
500
450
400
400
375
350
4 % DROOP
300
MW ->
300
250
250
5 % DROOP
200
200
150
125
100
100
50
0
0
48
48.5
49
49.5
50
HZ->
50.5
51
51.5
GOVERNOR TIME LAG
TIME TAKEN BY GOVERNOR TO JUST BEGIN CHANGING POWER OUTPUT
TO STABILISE FREQUENCY.
OR
TIME BETWEEN A CHANGE IN GENERATOR SPEED & CHANGE IN
TURBINE POWER.
TIME DELAY IN GOVERNOR OPERATION
• Dead band
• Valve opening
• Steam flow
0.25 sec
0.5 sec
4 seconds
• During transient state Governor is of little help.
• Effect is felt during steady state
BLOCKED GOVERNOR
BYPASSING 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 RATE
Approximate Freq
Decay Rate
In Hz / sec
5 X Lost Generation
=
--------------------------------------
Remaining Generation
Example:2200MW
Freq decay rate = (5 X 200) / 2000 =
200MW
Generation Lost
0.5 Hz /second
NEYVELI U-4 ON FGM ON 19/06/2003
220
50.4
FREQUENCY
210
50.2
50
49.8
190
49.6
180
GENERATION
49.4
170
49.2
160
11:00
11:15
11:30
11:45
12:00
TIME ->
12:15
12:30
12:45
49
13:00
HZ->
MW->
200
DROOP CHARACTERISTICS OF NYL U4
210
205
200
195
190
185
180
175
FREQ CHANGE 49.7 - >
50.4
0.7Hz
GEN CHANGE
205 ->
177
35MW
CHANGE IN GEN 28 MW FOR 0.7 Hz CHANGE IN FREQ
FOR 200 MW CHANGE IN GEN FREQ CHANGE REQD =
(200*0.7)/28 = 5 Hz
i.e 5*100 /50 = 10% Droop
170
49.6
49.7
49.8
49.9
50
50.1
50.2
50.3
50.4
50.5
NLY U6 ON FGM ON 15/07/03
195
50.6
190
50.4
185
50.2
180
MW -->
170
GENERATION
165
160
49.8
49.6
FREQUENCY
49.4
155
49.2
150
145
11:30
11:45
12:00
TIME-->
12:15
49
12:30
HZ -->
50
175
DROOP CHARACTERISTICS OF NYL U6
195
190
185
180
175
170
165
FREQ CHANGE 49.9 - >
50.5
0.6Hz
GEN CHANGE
191 ->
168
23MW
CHANGE IN GEN 24 MW FOR 0.6 Hz CHANGE IN FREQ
FOR 200 MW CHANGE IN GEN FREQ CHANGE REQD =
(200*0.6)/24 = 5 Hz
i.e 5*100 /50 = 10% Droop
160
49.8
49.9
50
50.1
50.2
50.3
50.4
50.5
50.6
50.7
IDUKKI GENERATION ON 16/07/2003
51
400
FREQUENCY
350
50.5
300
50
FREQ ->
MW
250
200
49.5
150
100
GENERATION
49
50
48.5
0
0
2
4
6
8
10
12
14
16
18
20
22
0
DROOP CHARACTERSTICS OF IDUKKI
400
350
300
250
200
150
100
50
0
49.3
49.4
49.5
49.6
49.7
49.8
49.9
50
50.1
49.1
49.2
49.3
49.4
49.5
49.6
49.7
49.8
POINT C
POINT D
POINT B
POINT A
POINT A - GENERATION LOSS
POINT B – GOVERNOR ACTION STARTED
POINT C - FREQUENCY AFTER GOVERNER ACTION
POINT D – FREQUENCY AFTER OPERATOR ACTION
49.9
BACKLASH
The distance through which one part of connected machinery, as a
wheel, piston, or screw, can be moved without moving the connected parts.
BOILER CONTROLS
• BOILER FOLLOWING SYSTEM
• TURBINE FOLLOWING SYSTEM
• INTEGRATED CONTROL SYSTEM
50
ADVANTAGES
1. 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
PROBLEMS
1.
2.
3.
4.
5.
Steam deposits on the valve stem .
Lubrication deposits (i.e., soaps, dirt, detergents,
etc.) in the top works of the valve exposed to the
elements.
Mechanical failures of the valve resulting from bent
stems, either in the valve proper or the upper
works, damaged split couplings, etc., all within
about a 6" area near the center of the valve
mechanism.
Galling of the piston in the hydraulic latch cylinder.
Jamming of the screw spindle in the larger
cylinder-type valve design due to forcing by
operations personnel
FREE GOVERNOR OPERATION
Mother of all Controls
Self healing mechanism
Collectively Control
Most equitable
Reduces risk of collapse
Makes restoration easy
World wide mandatory practice
210
420
200
360
190
300
180
240
170
180
STEADY STATE OPERATION
160
120
AT 50 HZ GEN= 190MW
150
60
140
49
49.1
49.2
49.3
49.4
49.5
49.6
49.7
49.8
FREQ IN HZ --->
49.9
50
50.1
50.2
50.3
50.4
0
50.5
UI PRICE -->
GENERATION IN MW --->
5% DROOP OF 210MW UNIT OF STATION A
VARIABLE COST = 140 Ps
OVER GENERATED BY 5%
5% DROOP OF 210MW UNIT OF STATION A
VARIABLE COST = 140 Ps
210
420
FREQUENCY DIPPED TO 49.8 HZ
GENERATION IN MW --->
360
190
300
180
240
170
180
160
120
150
60
140
49
49.1
49.2
49.3
49.4
49.5
49.6
49.7
49.8
FREQ IN HZ --->
49.9
50
50.1
50.2
50.3
50.4
0
50.5
UI PRICE -->
GENERATION INCREASED BY 10 MW
200
210
420
200
360
190
300
180
240
170
180
160
120
150
60
140
49
49.1
49.2
49.3
49.4
49.5
49.6
49.7
49.8
FREQ IN HZ --->
49.9
50
50.1
50.2
50.3
50.4
0
50.5
UI PRICE -->
GENERATION IN MW --->
OVER GENERATED BY 5%
5% DROOP OF 210MW UNIT OF STATION A
VARIABLE COST = 140 Ps
210
420
200
360
190
300
180
240
170
180
STEADY STATE OPERATION
160
120
AT 50 HZ GEN= 190MW
150
60
140
49
49.1
49.2
49.3
49.4
49.5
49.6
49.7
49.8
FREQ IN HZ --->
49.9
50
50.1
50.2
50.3
50.4
0
50.5
UI PRICE -->
GENERATION IN MW --->
5% DROOP OF 210MW UNIT OF STATION A
VARIABLE COST = 140 Ps
5% DROOP OF 210MW UNIT OF STATION A
VARIABLE COST = 140 Ps
INITIAL
210
420
FREQUENCY RISE UPTO 50.2 HZ
GENERATION IN MW --->
360
190
300
180
240
170
180
160
120
150
60
UI PRICE = 84 Ps
140
49
49.1
49.2
49.3
49.4
49.5
49.6
49.7
49.8
FREQ IN HZ --->
49.9
50
50.1
50.2
50.3
50.4
0
50.5
UI PRICE -->
GENERATION DECREASED BY 17MW
200
5% DROOP OF 210MW UNIT OF STATION B
VARIABLE COST = 70 Ps
INITIAL
210
420
FREQUENCY RISE UPTO 50.2 HZ
GENERATION IN MW --->
360
190
300
180
240
170
180
160
120
UI PRICE = 84 Ps
150
60
140
49
49.1
49.2
49.3
49.4
49.5
49.6
49.7
49.8
FREQ IN HZ --->
49.9
50
50.1
50.2
50.3
50.4
0
50.5
UI PRICE -->
GENERATION DECREASED BY 17MW
200
5% DROOP OF 210MW UNIT OF STATION B
SINCE VARIABLE COST OF
VARIABLE COST = 70 Ps
FINAL
STATION B < UI PRICE
210
420
200
360
190
300
180
240
170
180
160
120
150
60
140
49
49.1
49.2
49.3
49.4
49.5
49.6
49.7
49.8
FREQ IN HZ --->
49.9
50
50.1
50.2
50.3
50.4
0
50.5
UI PRICE -->
GENERATION IN MW --->
GENERATION INCREASED BY 17MW
5% DROOP OF 210MW UNIT OF STATION A
SINCE VARIABLE COST OF
VARIABLE COST = 140 Ps
FINAL
STATION A > UI PRICE
420
GENERATION FURTHER REDUCED BY
17MW
GENERATION IN MW --->
200
360
190
300
180
240
170
180
160
120
150
60
140
49
49.1
49.2
49.3
49.4
49.5
49.6
49.7
49.8
FREQ IN HZ --->
49.9
50
50.1
50.2
50.3
50.4
0
50.5
UI PRICE -->
210
PROPORTIONAL CONTROL
A simple form of control, where the controller
response is proportional to the control error.
∑
Kc
FB
Provides immediate controller response to setpoint
change, but speed may not settle exactly on SP using
proportional control alone
INTEGRAL CONTROL
Control action is control error integrated
over time.
∑
Kc
1/Tc
∫ fdt
FB
–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
PID Parameter Tuning – PI
only
DIFFERENTIAL CONTROL
In differential control, control action is based on
the change (derivative) of the control error.
∑
Kc
Td
df/dt
FB
Used to put the reigns on PI control to prevent
overshoot and oscillation and to add stability
PID CONTROL
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.
SUPPRESSED GOVERNOR OPERATION
OPEN
QUOTE
CERC ORDER ON ‘IEGC’ DATED 22.02.2002
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.
UNQUOTE
QUOTE
6.2(e)
CERC ORDER ON ‘IEGC’ DATED 22.02.2002
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.
UNQUOTE
QUOTE
CERC ORDER ON ‘IEGC’ DATED 22.02.2002
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.
UNQUOTE
QUOTE
CERC ORDER ON ‘IEGC’ DATED 22.02.2002
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.
UNQUOTE
FREE GOVERNOR MODE OF
OPERATION
CERC Order ON ‘IEGC’ dated 21.12.1999
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
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 368 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
th
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.
LETTERS
NLY-II U#4
NEYVELI U-4 ON FGM ON 19/06/2003
220
FREQUENCY
50.4
210
50.2
200
50
49.8
190
49.6
180
REDUCTION OF 21 MW IN 5 MTS
49.4
NYL U-4 GENERATION
170
49.2
160
11:00
49
11:15
11:30
11:45
12:00
12:15
12:30
12:45
13:00
Thank you