POWER GRID CORPORATION OF POWER GRID CORPORATION OF INDIA LIMITEDINDIA LIMITED

Presentation on Presentation on

‘‘FREE GOVERNOR OPERATION”FREE GOVERNOR OPERATION”

FREE GOVERNOR OPERATION

WHYFREQ COMPARISION

MAY-02 & MAY-03

GOVERNOR

BEFORE GOVERNORGOVERNOR RESPONSE

IN NER

DEAD BAND GOVERNOR TIME LAG

BLOCKED GOVERNOR

ROLE

DROOPFREQUENCY DECAY RATE BACKLASH

TYPES OF CONTROLSDROOP RESPONSE IN SR

ABT & GOVERNOR

ADVANTAGES

GOVERNOR TYPES

TIME DELAY

CHARACTERISTICS

PROBLEMS LIST OF GENERATORS

FREQUENCY BASED DISPATCH

FREQUENCY BASED DISPATCH

SUPPRESSED GOVERNORACTION

PID CONTROL PTI TAPE ORDERS

ORDERS

IEGC 6.2 (e) & 6.2(f)IEGC 1.6 IEGC 6.2 (g)

NLY PETITIONIEGC 6.2 (h) WEST BENGAL

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 Frequency control

• Free Governor Opertaion

• Under Frequency Operation

PRIMARY CONTROLSPRIMARY CONTROLS

ABT AND GOVERNORABT AND GOVERNOR

POST 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

MISCONCEPTIONMISCONCEPTION

Governors attempt to restore frequency to normal.

In reality, Governors attempt to restore load generation balance, using frequency change as a signal.

CHARACTERISTICSCHARACTERISTICS

1.1. 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 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 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 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

0

40

80

120

160

200

49 49.5 50 50.5 51 51.5

FREQ IN HZ --->

GE

NE

RA

TIO

N I

N M

W -

-->

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 --->

GE

NE

RA

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 --->

GE

NE

RA

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 --->

GE

NE

RA

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 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.

• 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 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 RATEFREQUENCY DECAY RATE

Approximate 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

FR

EQ

->

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

ADVANTAGESADVANTAGES

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

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 OPERATION

Mother 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 --->

GE

NE

RA

TIO

N I

N M

W -

-->

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 --->

GE

NE

RA

TIO

N I

N M

W -

-->

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 --->

GE

NE

RA

TIO

N I

N M

W -

-->

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 --->

GE

NE

RA

TIO

N I

N M

W -

-->

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 --->

GE

NE

RA

TIO

N I

N M

W -

-->

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 --->

GE

NE

RA

TIO

N I

N M

W -

-->

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 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 --->

GE

NE

RA

TIO

N I

N M

W -

-->

0

60

120

180

240

300

360

420

UI P

RIC

E -

->

FINAL

GENERATION FURTHER REDUCED BY 17MW

SINCE VARIABLE COST OF

STATION A > STATION B

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 --->

GE

NE

RA

TIO

N I

N M

W -

-->

0

60

120

180

240

300

360

420

UI P

RIC

E -

->

GENERATION INCREASED BY 17MW

FINALSINCE VARIABLE COST OF

STATION B < STATION A

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 CONTROL

In 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

Thank you