presentation on frequency control and

1

PRESENTATION

ON

FREQUENCY CONTROL

AND

FREE GOVERNOR OPERATION

TO THE OFFICERS OF

CENTRAL ELECTRICITY AUTHORITY

On 4th April, 2005

by

V.K. Agrawal

SRLDC, Bangalore

2

PRESENTATION OVERVIEW

REGIONAL GRIDS – QUICK FACTS

GRID OPERATION – TYPICAL ISSUES IN THE PAST

GRID PRESENT STATUS – CARDINAL EVENTS

FGMO – STIPULATIONS IN IEGC

FREE GOVERNOR OPERATION – THE BASICS

FGMO – CASE STUDIES IN DIFFERENT REGIONS

ISSUES OF FURTHER INTEREST – ACTION PLAN

3

REGIONAL GRIDS

QUICK FACTS

4

SOUTHERN REGION

WESTERNREGION

EASTERN REGION

NORTHERN REGION

NORTH-EASTERN REGION

INSTALLED CAPACITY

NORTHERN :- 31,230 MW

EASTERN :- 17,697 MW

SOUTHERN :- 31,931 MW

WESTERN :- 32,354 MW

NORTH-EASTERN :- 2,357 MW

TOTAL 115,569 MW

REGIONAL GRIDS

5

SOUTHERN REGION

WESTERNREGION

EASTERN REGION

NORTHERN REGION


‘ ELECTRICAL’

REGIONS1

2

3

SAME FREQUENCY FROM GUJARAT TO ARUNACHAL PRADESH WITH EFFECT FROM MARCH 2003

ABOUT 2800 KMS! APART

6

SOUTHERN REGION

WESTERNREGION

EASTERN REGION

NORTHERN REGION


‘ELECTRICAL’

REGIONS

1

2

WITH THE COMMISSIONING OF THE TALA PROJECT CONNECTING THE EASTERN AND NORTHERN GRIDS, INDIA WILL HAVE ONLY TWO GRIDS

7

Growth of installed capacity Growth of installed capacity for electricity in Indiafor electricity in India

0

20000

40000

60000

80000

100000

120000

1990

-91

1991

-92

1992

-93

1993

-94

1994

-95

1995

-96

1996

-97

1997

-98

1998

-99

1999

-00

2000

-01

2001

-02

2002

-03

2003

-04

in MW

8

Power development - 16th EPS projections :

975

719529507

Mar.'01 (act.) Mar.'02 (est.) Mar.'07 (est.) Mar.'12 (est.)

157107

1157058513278037

Peak requirement

in MW

Energy requirement

in BU

9

Sourcewise Sourcewise composition of composition of

installed capacity in installed capacity in IndiaIndia

((1,15,569 in 2004)1,15,569 in 2004)2.40% 1.70% 26%

70%

HydroThermalNuclearWind

10

13000

14000

15000

16000

17000

18000

19000

20000

21000

22000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

TIME IN HRS --->

DE

MA

ND

IN

MW

---

>

MONSOON SUMMER WINTER

TYPICAL LOAD CURVE OF SR

WINTER

MONSOON

SUMMER

EVENING PEAK

WEATHER

RESERVOIR CONSUMPTION SECTOR-WISE HYDRO THERMAL

11

Load Curves of Northern Region for Typical Summer & Winter Season

16000

17000

18000

19000

20000

21000

22000

23000

24000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hours

MW

Summer Summer high hydro Winter

12

WR Load Curve (Hourly Average)

18500

19500

20500

21500

22500

23500

24500

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Time

MW

-->

May Catered Demand(summer) Jul Catered Demand(Monsoon)

Dec Catered Demand(Winter)

13

SEASONAL VARIATION OF HOURLY DEMAND

4000

4500

5000

5500

6000

6500

7000

7500

8000

8500

9000

1 2 3 4 5 6 7 8 9 101112131415161718192021222324

HOUR

DM

D (

MW

)

SUMMER MONSOON WINTER

ER

14

GRID OPERATION

TYPICAL ISSUES IN THE PAST

15

GRID OPERATION – TYPICAL ISSUES IN PAST

• LOW / HIGH FREQUENCY PROBLEMS

– FREQUENCY EXCURSES TO LOW/HIGH VALUES

• LOW / HIGH VOLTAGE OPERATION

– CRITICALLY LOW VOLTAGES AT LOAD CENTRES

– SUBSTANTIALLY HIGH VOLTAGES AT FAR ENDS

• SYSTEM BROWNOUTS / BLACK OUTS

– SEPERATION OF SYSTEMS / LOSS OF LOAD

• ECONOMIC IN-STABILITY / INCREASED ELECTRICAL LOSSES– UNRELIABLE / INEFFICIENT OPERATION OF EQUIPMENT

16

GRID PRESENT STATUS

17

GRID OPERATION – PRESENT STATUS

STABILISED SYSTEM FREQUENCY

IMPROVED VOLTAGES

MERIT ORDER OPERATION

OPERATIONAL EXCELLENCE

INTER REGIONAL EXCHANGES

IMPROVED GRID SECURITY

JAN - 02 JAN - 03 Vol

18

GRID PRESENT STATUS

CARDINAL EVENTS

19

GRID PRESENT STATUS -- CARDINAL EVENTS

• AVAILABILITY BASED TARIFF

• UNIFIED LOAD DESPATCH SCHEME

• GENERATION ADDITION

• INTERREGIONAL AC / HVDC LINKS

• REFORMS IN POWER SECTOR

SCHD DRWL

20

FGMO

STIPULATIONS IN IEGC

21

EXTRACTS FROM INDIAN ELECTRICITY GRID CODE

Section 6.2(e)

“ All generating units which are synchronized 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%.”

22


Section 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.”

23


Section 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 percent (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 (10MW for NER) not complying with the above requirement, shall be kept in operation (synchronized with the grid) only after obtaining the permission of RLDC.

24


Section 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) percent per minute or as per manufacturer’s limits. However if the frequency falls below 49.5 Hz, all partly loaded generating units shall pick up additional load at a faster rate according to their capability.”

25


Section 1.6The 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 the date for implementation of the Commercial mechanism for

(i) All generating units of installed capacity 200 MW and above and reservoir based hydro units of installed capacity 50 MW and above in SR, ER, NR & WR.

(ii) All thermal and reservoir based hydro generating units of installed capacity 10 MW and above in North Eastern Region.

26


Section 1.6 (contd.)

For all other generating units the date of implementation of stipulations under section 4.8(c), 4.8(d), 6.2(e), 6.2(f), 6.2(g) and 6.2(h) would be three months after the date of implementation of the Commercial mechanism (ABT)

27

FREE GOVERNOR OPERATION

THE BASICS

28

VARIATION IN FREQUENCY

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.

29

PRIMARY CONTROLSTO REGULATE FREQUENCY

Relief by frequency dependent load

Free Governor Operation

Under Frequency Operation

30

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 speed (frequency), governor responses by causing valves/gates to open/close to increase/decrease the input to the prime mover

The notion that Governor attempts to restore frequency to normal is a misconception. In reality, Governors attempts to restore load generation balance, using frequency change as a signal.

31

PRIMARY CONTROL - GOVERNOR ACTION

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.

32

DROOP

Droop is 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%

33

FREQUENCY VS LOAD CURVE

50Hz

52.5Hz

51.25 Hz

100%

50%

0% Frequency in Hz

Load in %

Droop = 5%

34

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

100

40

200

300

400

80

120

160

35

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

36

GOVERNING SYSTEM

Hydraulic system has a droop of 5%

Electro-hydraulic system has a droop adjustable from 2.5 to 8%. It is normally set at 5%

In ehtc, droop characteristics is realised through frequency influence on load controller

Frequency influence also acts in cmc for combustion controls

37

BLOCKED GOVERNOR

Blocking of governor is bypassing the governing feedback mechanism to maintain fixed generator output.

38

FREE GOVERNOR MODE OF OPERATION

CASE STUDY FOR NORTHERN REGION

39

EXTRACTS FROM MINUTES OF NREB BOARD MEETING HELD AT SHIMLA

ON 14th JUNE 2003

“Northern Regional Electricity Board endorsed the decision of Technical Coordination Committee (TCC) to implement free governor mode of operation (FGMO) from 0000 hrs of 1st Oct, 2003”

40

DETAILS OF GENERATING UNITS IDENTIFIED FOR FGMO IN NORTHERN REGION

THERMAL (COAL-FIRED) STATIONS:

Sl No. Power Station Agency Capacity

01. Badarpur NTPC 2 x 210 = 420 02. Singaruli NTPC 5 x 200 + 2 x 500 = 2000 03. Rihand NTPC 2 x 500 = 1000 04. Dadri NTPC 4 x 210 = 840 05. Unchahar NTPC 4 x 210 = 840 06. Panipat HPGC 2 x 210 = 420 07. Ropar PSEB 6 x 210 = 1260 08. Lehra Mohabbat PSEB 2 x 210 = 420 09. Kota RRVUNL 3 x 210 = 630 10. Suratgarh RRVUNL 5 x 250 = 1250 11. Obra UPRVUNL 5 x 200 = 1000 12. Anpara UPRVUNL 3 x 210 + 2 x 500 = 1630

Total 11710

41

DETAILS OF GENERATING UNITS IDENTIFIED FOR FGMO IN NORTHERN REGION

HYDRO STATIONS (WITH PONDAGE) :

Sl No. Power Station Agency Capacity

01. Bhakra(L) & (R) BBMB 5 x 108 + 5 x 157 = 1325 02. Pong BBMB 6 x 66 = 396 03. Chamera NHPC 3 x 180 = 540 04. RSD PSEB 4 x 150 = 600 05. Rana Pratap Sagar(RPS) RRVUPNL 4 x 43 = 172 06. Rihand UPJVUNL 6 x 50 = 300 07. Ram Ganga UJVUNL 3 x 66 = 198 08. Jhakri SJVNL 2 x 250 = 500

Total 4031 GRAND TOTAL: Availability on a typical day considering: 100% of 500 MW Units = 3000 MW 80% of 200/210/250/195 MW Units = 6968 MW 50% of Reservoir Hydro Units = 2015 MW Total = 11983 MW

42

UNIT SIZE & GOVERNING SYSTEM

S No

Category Total Units

Capacity

(MW)

1 500 MW units equipped with EHG governing system and coordinated controls through CMC/ULC/APC: Singrauli,Rihand,Anpara

6 3000

2 210/250 MW units equipped with EHG governing system & coordinated controls through CMC: Kota, Dadri(Th), Unchhar-II, Lehra,Suratgarh

16 3560

3 210 MW units equipped with EHG governing system and having manual controls (Without CMC):

Unchahar-I, Ropar, Panipat, Anpara-A

13 2730

4 200/210 MW units quipped with hydro mechanical governing system and having manual controls

(Singrauli, Obra-B, Badarpur)

12 2420

5 Total 47 11710

44

FREQUENCY PROFILE FOR 12-10-2003 AND 05-10-2003

48.5

49.0

49.5

50.0

50.5

51.0

51.5

Time

05-10-2003

48.5

49.0

49.5

50.0

50.5

51.0

51.5

12-10-2003

Fre

qu

ency

(H

z)

45

FREQUENCY PROFILE OF NORTHERN REGION

48.048.549.049.550.050.551.051.552.0

Time

27-Oct-2002

48.0

48.5

49.0

49.5

50.0

50.5

51.0

51.5

52.027-Oct-2003

Lowest FVI 0.34

Freq

uenc

y (H

z)

46

FREQUENCY PROFILE OF NORTHERN REGION

48.048.549.049.550.050.551.051.552.0

Time

29-Oct-2002

48.0

48.5

49.0

49.5

50.0

50.5

51.0

51.5

52.0

29-Oct-2003

FVI 0.46

Freq

uenc

y (H

z)

47

Above 50.5 Hz Below 49.0 Hz

Period % time in IEGC frequency band

(49.0-50.5 Hz)

No. of Excursions

% of time

No. of Excursions

% of time

7th Oct-30 Oct (Post FGMO)

99.12 10 0.28 % 37 0.59 %

1st Sept – 6th Oct (Pre-FGMO)

89.45 378 10.26 % 36 0.30 %

COMPARISON OF FREQUENCY PROFILE

FGMO

48


CASE STUDY FOR SOUTHERN REGION

49

EXTRACTS FROM MINUTES OF 132nd SREB BOARD MEETING HELD ON

ON 5th JULY 2003

The free governor mode of operation (FGMO) shall be implemented in SR from 0000 hrs of 1st Aug. 2003

50

DETAILS OF GENERATING UNITS IDENTIFIED FOR FGMO IN SOUTHERN REGION

THERMAL STATIONS

S. No Power Station Agency CapacityInstalled Capacity

(MW)

1 KOTHAGUDAM APGENCO 2 * 250 500

2 SIMHADRI NTPC 2 * 500 1000

3 VIJAYAWADA APGENCO 6 * 210 1260

4 RAYALASEEMA APGENCO 2 * 210 420

5 LANCO AP IPP 2 * 115 + 1 * 125 355

6 BSES AP IPP 1 * 140 + 1 * 80 220

7 RAICHUR TPS KPCL 7 * 210 1470

8 NORTH CHENNAI TNEB 3 * 210 630

9 TUTUCORIN TNEB 5 * 210 1050

10 METTUR TNEB 4 * 210 840

11 ST - CMS TN IPP 1 * 250 250

12 NEYVELI II NLC 7 * 210 1470

13 NEYVELI TPS I (Exp) NLC 2 * 210 420

14 RAMAGUNDAM NTPC 3 * 200 + 3 * 500 2100

TOTAL 11985

51

HYDRO STATIONSS. No Power Station Agency Capacity

Installed Capacity (MW)

1 SRISAILAM RB APGENCO 7 * 110 770

2 SRISAILAM LB APGENCO 6 * 150 900

3 UPPER SILERU APGENCO 4 * 60 240

4 LOWER SILERU APGENCO 4 * 115 460

5 N'SAGAR APGENCO 1 * 110 + 7 * 100 810

6 SHARAVATHI KPCL 10 * 103.4 1034

7 NAGJHERI KPCL 3 * 150 + 3 * 135 855

8 VARAHI KPCL 2 * 115 230

9 SHARAVATHI TAIL RACE KPCL 4 * 60 240

10 KADRA KPCL 3 * 50 150

11 SUPA KPCL 2 * 50 100

12 KUTTIADI EXTN. KSEB 1 * 50 50

13 IDDUKKI KSEB 6 * 130 780

14 LOWER PERIYAR KSEB 3 * 60 180

15 SABARIGIRI KSEB 6 * 50 300

16 KADAMPARAI TNEB 4 * 100 400

17 KUNDAH PH 3 TNEB 3 * 60 180

18 KUNDAH PH 4 TNEB 2 * 50 100

19 KODAYAR 1 TNEB 1 * 60 60

20 ALIYAR TNEB 1 * 60 60

21 METTUR TUNNEL TNEB 4 * 50 200

TOTAL 8099

52

STATUS OF FGMO IN SR (ABSTRACT)

STATE

CAPACITY ON FGMO ( MW )

HYDRO50 MW(75 NOS)

THERMAL/ GAS

200 MW(50 NOS)

TOTAL

ANDHRA PRADESH 3,180 3,755 6,935

KARNATAKA 2,509 1,260 3,769

KERALA 1,010 --- 1,010

TAMIL NADU 800 2,520 3,320

ISGS --- 3,990 3,990

TOTAL 7,499 11,525 19,024

53

CAPACITY ON FGMO IN SR ( HYDRO < 50 MW & THERMAL < 200 MW )

STATECAPACITY ON FGMO ( MW )

HYDROTHERMAL/

GASTOTAL

ANDHRA PRADESH 0 760 760

KARNATAKA 120 0 120

KERALA 433 0 433

TAMIL NADU 780 390 1,170

ISGS 0 0 0

TOTAL 1,333 1,150 2,483

5447.5

48.0

48.5

49.0

49.5

50.0

50.5

00

01

02

03

04

05

06

07

08

09

10

11

12

13

14

15

16

17

18

19

20

21

22

23

48.5

49.0

49.5

50.0

50.5

51.000

01

02

03

04

05

06

07

08

09

10

11

12

13

14

15

16

17

18

19

20

21

22

23

FREQUENCY PROFILE OF SOUTHERN REGIONBetween 49-50.5HZ :-

100%02-AUG-03

48.5

49.0

49.5

50.0

50.5

51.0

00

01

02

03

04

05

06

07

08

09

10

11

12

13

14

15

16

17

18

19

20

21

22

23

02-JULY-03 Between 49-50.5HZ :- 92.8%

Between 49-50.5HZ :- 6.9%02-AUG-02

5548.5

49.0

49.5

50.0

50.5

51.0

00

01

02

03

04

05

06

07

08

09

10

11

12

13

14

15

16

17

18

19

20

21

22

23

48.5

49.0

49.5

50.0

50.5

51.000

01

02

03

04

05

06

07

08

09

10

11

12

13

14

15

16

17

18

19

20

21

22

23

FREQUENCY COMPARISION OF SOUTHERN REGION

09-SEP-04

09-JULY-03

56

Above 50.5 Hz Below 49.0 Hz

Period % time in IEGC frequency band

(49.0-50.5 Hz)

No. of Excursions

% of time

No. of Excursions

% of time

1st Jul-31st Jul 03 (Pre- FGMO)

98.73 52 0.72 % 16 0.55 %

1st Aug-31st Aug 03 (Post-FGMO)

99.45 43 0.54 % 2 0.01 %

COMPARISON OF FREQUENCY PROFILE

FGMO

57


CASE STUDY FOR WESTERN REGION

58

CAPACITY WISE (MW) CLASSIFICATION OF

GENERATING UNITS IN WRConstituent No.of Units Type (> 200 MW) LMW KWU GEB 2710 1240 1470 MPSEB 1670 830 840 CSEB 840 NIL 840 MSEB 5480 3140 2340 TPC 1000 NIL 1000 BSES 500 NIL 500 NTPC 4360 1260 3100 WR 16560 6470 10090

59

TYPE WISE CLASSIFICATION OF GENERATING UNITS IN WR

Constituent No.of units Type (> 200 MW) LMW KWU GEB 13 6 7 MPSEB 8 4 4 CSEB 4 0 4 MSEB 22 15 7 TPC 2 0 2 BSES 2 0 2 NTPC 14 6 8 WR 65 31 34

60

Units under FGMO on 31.1.2004Sl.No. Name of

constituents No. of generating units to be kept on FGMO

Actual no. of machines kept on FGMO

LMW/ LMZ

KWU Total LMW/ LMZ

KWU Total

1. MSEB 15 7 34 0 3 3 2. GEB 9 4 13 5 0 5 3. MPSEB 4 4 8 4 3 7 4. CSEB 0 4 4 0 3 3 5. NTPC(KSTPS

& VSTPS) 6

8 14 6 8 14

6. BSES 0

2 2 0 2 2

7. TPC 0

2 2 0 2 2

Total 77 36

61

Fig.2 and 3: Frequency improvement after FGMO

48.5

49

49.5

50

50.5

51

0:03

1:43

3:18

4:53

6:28

8:03

9:38

11:13

12:48

14:23

15:59

17:44

19:29

21:04

22:50

48.5

49

49.5

50

50.5

51

0:03

1:43

3:18

4:53

6:28

8:03

9:38

11:13

12:48

14:23

15:59

17:44

19:29

21:04

22:50

TIME

Frequency Profile of 25th January,2004

Frequency Profile of 18th January,2004

62

Frequency improvement after FGMO

Indices 18.01.2004 25.01.2004

Average freq. 49.78 Hz 50 Hz

Std deviation 0.3 Hz 0.2 Hz

Average of squares of morning deviation

0.0030 Hz 0.0017 Hz

Average of deviations from 15-minutes average frequency

0.040 Hz 0.004 Hz

63


CASE STUDY FOR EASTERN REGION

64

FREQUENCY COMPARISION

48.0

48.5

49.0

49.5

50.0

50.5

51.0

0:00 2:24 4:48 7:12 9:36 12:00 14:24 16:48 19:12 21:36 0:00

TIME

FR

EQ

UE

NC

Y

26/1/04 26/12/03

65


48.0

48.5

49.0

49.5

50.0

50.5

51.0

51.5

52.0

0:00 2:24 4:48 7:12 9:36 12:00 14:24 16:48 19:12 21:36 0:00

TIME

FR

EQ

UE

NC

Y

26/1/04 26/1/03

66


48.0

48.5

49.0

49.5

50.0

50.5

51.0

0:00 2:24 4:48 7:12 9:36 12:00 14:24 16:48 19:12 21:36 0:00

TIME

FR

EQ

UE

NC

Y

26/1/04 2/1/04

67

REDUCED FREQUENCY BAND WITH IMPLEMENATION OF FGMO

FREQUENCY DEVIATION REDUCED FURTHER FREQUENCY DEVIATION REDUCED FURTHER FROM 22FROM 22NDND JANUARY,04 JANUARY,04

00.00

00.10

00.20

00.30

00.40

00.50

00.60

00.70

00.80

00.90

01.00

1-J

an

-03

1-F

eb

-03

1-M

ar-

03

1-A

pr-

03

1-M

ay-0

3

1-J

un

-03

1-J

ul-

03

1-A

ug

-03

1-S

ep

-03

1-O

ct-

03

1-N

ov-0

3

1-D

ec-0

3

1-J

an

-04

1-F

eb

-04

1-M

ar-

04

DATE

ST

D

FGMO IMPLEMENTATION

68

ISSUES OF IMPORTANCE

ACTION PLAN

69

Limitations and Constraints(AS REPORTED BY GENRATORS)

Poor coal quality

(All mills are usually in service – no further margins)

Old units, weak boiler parts(Very often operation at throttle pressure below nominal) Commercial reasons

70

Limitations and Constraints(AS REPORTED BY GENRATORS)

Fear of thermal stresses due to cyclic variation in pressure and temperature.

Fears of choking of mills (when coal quality is poor).

Fear of safety valves propping up.

71

Other Related Issues

Participation in the scheme by all the generators is essential so that the participating units are not subjected to large variations. Commercial mechanism to be conducive for participation in the scheme. In the event of loss of generation it should be made up by reserves and/or requisite load shedding. In order to take care of secondary control a well planned and judicious methodology should follow.

73

MONSOONS

SOUTH WEST MONSOON NORTH EAST

MONSOON

74

GRID OPERATION:GRID OPERATION: A TIGHT ROPE WALK A TIGHT ROPE WALK

BLACK-OUTVOLTAGE

COLLAPSE IN-ECONOMIC

OPERATION

INSTABILITYPOWER

SWINGSINCREASED

LOSSES

75

STABILISED SYSTEM FREQUENCY

• TYPICAL FREQUENCY CURVE

• SCATTER DIAGRAM

• HISTOGRAM OF FREQUENCY

• FREQUENCY DURATION CURVE

• Df/dT CURVE

• RECORD FVI OF 0.04

76

47.50

48.00

48.50

49.00

49.50

50.00

50.50

51.00

25 26 27 28 29 30 31

DAYS ----->

FR

EQ

UE

NC

Y IN

HZ

---

->FREQUENCY PROFILE

2002, 2003 & 2004

77

FREQUENCY DURATION CURVE AUG TO OCT 04, 03 & 02

47.50

48.00

48.50

49.00

49.50

50.00

50.50

51.00

1 1117 2233 3349 4465 5581 6697 7813 8929 10045 11161 12277 13393 14509 15625 16741 17857 18973 20089 21205

% OF TIME --->

FR

EQ

UE

NC

Y IN

HZ

---

>

0 10 20 30 40 50 60 70 80 90 100

2004

2003

<49.049.0 & <49.5

49.5 & <50.5

50.5 & Above

Max Min Avg FVI St. Dev

2004 0.03 1.46 98.28 0.23 50.82 48.62 49.95 0.31 0.12

2003 0.17 8.32 90.66 0.85 50.85 48.60 49.81 0.95 0.18

2002 73.62 12.45 12.84 1.09 51.08 47.69 48.63 23.59 0.44

2002

78

Voltage at Bangalore Jan 02 & 03

79

Percentage of time frequency remained within the IEGC band (49.0-50.5 Hz) in Northern Region

60

65

70

75

80

85

90

95

100

December January February March April May June July August September October November

Perc

enta

ge o

f tim

e

pre-ABT

post-ABT

80

Singrauli & Rihand

2555

2530

2491 25

05

2200

2300

2400

2500

2600

2700

Pre ABT(Dec 01-Nov 02) Post ABT(Dec 02-Nov 03)

Av

era

ge

MW

Declared Capability Injection Schedule

Unchahar-1 & 2

691

687

599

653

500

550

600

650

700

750


Ave

rag

e M

W

Declared Capability Injection Schedule

Dadri (T)

711

640

619

717

500

550

600

650

700

750

800


Ave

rag

e M

W

Declared Capability Injection schedule

Anta, Auraiya & Dadri

1478

1336

1330

1636

1100

1200

1300

1400

1500

1600

1700

1800


Ave

rag

e M

W

Declared Capabilty Injection Schedule

81

Schedules as percentage of Declared Capability (DC)

97.5%

86.7%

89.9% 90.4%

99.0%

95.0%

86.3%

81.3%

75.0%

80.0%

85.0%

90.0%

95.0%

100.0%

105.0%

Pithead Unchahar-I +II Dadri (T) Combined cycle ISGS

pre-ABT (Dec 01-Nov 02)

post-ABT (Dec 02-Nov 03)

82

VARIABLE COST(Ps) OF POWER STATION IN SR AS ON JUNE 2004

0

2000

4000

6000

8000

10000

12000

14000

16000

18000P

ON

DY

PC

L (3

2.5

MW

)(19

.61

PS

)

NE

YV

ELI

-II S

TG

1 *

*(63

0 M

W)(

67.9

9 P

S)

KO

VIL

KA

LAP

PA

L *(

105

MW

)(68

PS

)

JEG

UR

UP

AD

U (

GA

S)(

216

MW

)(82

PS

)

SP

EC

TR

UM

(G

AS

)(20

8 M

W)(

83 P

S)

VIJ

JES

WA

RA

M -

I(10

0 M

W)(

84 P

S)

VIJ

JES

WA

RA

M -

II(17

2.5

MW

)(86

PS

)

B S

E S

(A

P)(

GA

S)(

140

MW

)(87

PS

)

RE

INS

CA

LCIN

ING

LT

D.(

41 M

W)(

90 P

S)

RA

MA

GU

ND

AM

(210

0 M

W)(

90 P

S)

LAN

CO

(350

MW

)(91

.48

PS

)

NE

YV

ELI

-II S

TG

-II *

*(84

0 M

W)(

94.6

1 P

S)

SIM

HA

DR

I(10

00 M

W)(

96 P

S)

RA

MA

GU

ND

AM

-B(6

2.5

MW

)(96

PS

)

VIJ

AY

AW

AD

A T

.P.S

.-1&

2(10

50 M

W)(

101

PS

)

VIJ

AY

AW

AD

A T

.P.S

.-3(

210

MW

)(10

1 P

S)

KO

TH

AG

UD

EM

(B)(

210

MW

)(10

8 P

S)

RA

ICH

UR

.T.P

S. *

*(12

60 M

W)(

110

PS

)

KO

TH

AG

UD

EM

(A)(

240

MW

)(11

0 P

S)

KO

TH

AG

UD

EM

(C)(

220

MW

)(12

3.1

PS

)

KO

TH

AG

UD

EM

(D)(

500

MW

)(12

4 P

S)

RA

YA

LAS

EE

MA

TP

P(4

20 M

W)(

126

PS

)

NO

RT

H M

AD

RA

S.T

.P.S

(630

MW

)(13

0.98

PS

)

TU

TU

CO

RIN

.T.P

.S(1

050

MW

)(13

3.5

PS

)

ME

TT

UR

.T.P

.S(8

40 M

W)(

150

PS

)

V S

P *

(120

MW

)(16

9.11

PS

)

ST

-CM

S(2

50 M

W)(

171

PS

)

NE

YV

ELI

-I(6

00 M

W)(

185.

86 P

S)

EN

NO

RE

.T.P

.S(4

50 M

W)(

190.

2 P

S)

L V

S(3

7.8

MW

)(20

0 P

S)

YE

LEH

AN

KA

DE

ISE

L(12

7.92

MW

)(20

3.36

PS

)

NA

VB

HA

RA

T(3

5 M

W)(

205

PS

)

BR

AH

MA

PU

AM

D P

P(1

06.5

MW

)(21

4 P

S)

NE

LLO

RE

(30

MW

)(22

5 P

S)

B S

E S

(K

ER

ALA

)(16

5.5

MW

)(22

5 P

S)

TH

AN

NE

ER

BA

VI(

235

MW

)(22

8 P

S)

JIN

DA

L(26

0 M

W)(

247

PS

)

BA

LAJI

(SA

MA

YA

NA

LLU

R)(

105

MW

)(24

7 P

S)

KO

ZH

IKO

DE

DP

P(1

28.8

MW

)(25

0 P

S)

GM

R V

AS

AV

I(19

6 M

W)(

254

PS

)

SA

MA

LPA

TT

Y IP

P(1

05 M

W)(

263

PS

)

TA

TA

DE

ISE

L(81

.3 M

W)(

280

PS

)

KA

YA

MK

ULA

M N

TP

C(3

50 M

W)(

290

PS

)

KA

SA

RG

OD

P C

L(2

1 M

W)(

300

PS

)

RA

YA

LAS

EE

MA

(37.

8 M

W)(

330

PS

)

PP

NA

LLU

R(3

30.5

MW

)(41

5 P

S)

BA

SIN

BR

IDG

E(1

20 M

W)(

468

PS

)

CU

MU

LA

TIV

E IN

ST

AL

LE

D C

AP

AC

ITY

IN M

W

0

50

100

150

200

250

300

350

400

450

VA

RIA

BL

E C

OS

T IN

Ps/

UN

IT

VARIABLE COST

CUMULATIVEINSTALLE

ABOUT 7000 MW OF CAPACITY IS BELOW 100 Ps

ABOUT14200 MW OF CAPACITY IS BELOW 200 Ps

ABOUT 16000 MW OF CAPACITY IS BELOW 300 Ps

CUM. INS. CAP.

83

49.72 HZ

84

MERIT ORDER : UNITS BOXED UP

POWER STATION STATE CAPACITY(MW) FUELVARIABLE

COST

TATA DIESELKARNATAK

A 79 DIESEL 308

RAYALSEEMA DGPP

KARNATAKA 27 DIESEL 360

YELEHANKA DIESEL

KARNATAKA 128 DIESEL 314

THANRBHAVIKARNATAK

A 220 NAPTHA 325

SUB-TOTAL 454

BRAHAMPURAM DPP KERALA 107 DIESEL 275

BSES KERALA 157 NAPTHA 308

KASARGODE PCL KERALA 22 NAPTHA 298

KAYAMKULAM KERALA 360 NAPTHA 322

SUB-TOTAL 646

BASIN BRIDGETAMIL NADU 120 NAPTHA 584

P.P.NALLURTAMIL NADU 330 NAPTHA 415

SUB-TOTAL 450

TOTAL 1550

85

DEEP VALLEY

DEEP VALLEY

SHARP

PEAK

86

KADAMPARAI PUMP OPERATION

-300

-200

-100

0

100

200

300

400

5000:

001:

002:

003:

004:

005:

006:

007:

008:

009:

0010

:00

11:0

012

:00

13:0

014

:00

15:0

016

:00

17:0

018

:00

19:0

020

:00

21:0

022

:00

23:0

00:

00

TIME ---->

IN M

W --

-->

48.50

49.00

49.50

50.00

50.50

51.00

FREQ

UENC

Y IN

HZ

---->

GENERATOR MODE

PUMP PUMP

SAVINGS OF RS 40 LAKHS EVERY DAY

INVESTMENT OF 1600 CRORES SAVED

87

OPPORTUNISTIC UI TRADEEXPORT TO WR ON 13/05/03-14/05/03

-300

-200

-100

0

100

200

300

400

500

600

00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 00 01 02 03 04 05 06 07 08

49

49.2

49.4

49.6

49.8

50

50.2

50.4

50.6

50.8

51POWER EXPORT TO WR ON

UI BASIS DURING LOAD CRASH

FREQ

88

OPTIMAL RESERVOIR UTILISATIONIDUKKI IN KERALA

KERALA SAVED RS 50 CRORES BY EFFICIENT UTILISATION OF THE RESERVOIRS AT IDUKKI!

POWERGRIDs 400 KV MADURAI-TRIVANDRUM LINE WILL HELP KERALA

SAVE EVEN MORE ENERGY IN THE COMING

YEAR

PLANT OPERATORS AT IDUKKI THINK OF THE RESERVOIR LEVEL IN RUPEES RATHER

THAN IN FEET!!!

Rs. Rs.

Rs.

Rs.

Rs.

Rs.Rs.

Rs.

Rs.

Rs.

Rs.

Rs.

Rs.

Rs.

Rs.Rs.

89

Growth Of Inter Regional Energy Exchanges

73508230

9730

13000

22500

0

5000

10000

15000

20000

25000

1999-2000 2000-2001 2001-2002 2002-2003 2003-2004

Year

To

tal M

U D

uri

ng

Th

e Y

ear

IR Energy Exchanges

90

MAJOR AND MINOR DISTURBANCES SINCE 1994

0

1

2

3

4

5

6

7

8

9

10N

UM

BE

R O

F D

IST

UR

BA

NC

ES

---

----

->

1994

-95

1995

-96

1996

-97

1997

-98

1998

-99

1999

-00

2000

-01

2001

-02

2002

-03

2003

-04

2004

-05

YEAR ->

MAJOR MINOR

NO DISTURBANCES DESPITE LOSING ENTIRE SUPER GENERATING PLANTS LIKE

RAMAGUNDAM,VIJAYAWADA,KOTHAGUDEM, NORTH CHENNAI, SHARAVATHY ETC

91RTU RTU RTU

SUB LDC SUB LDC SUB LDC

SLDC SLDC SLDC

ERLDC

WRLDC NRLDC SRLDC

NERLDC

NLDC

32 Nos.

51 Nos.

1160Nos.

Unified Grid OperationUnified Grid Operation

5 Nos.

NationalLevel

RegionalLevel

State HQLevel

Group / Distt Level

Plant / Sub-Station Level

92

Growth of installed capacity Growth of installed capacity for electricity in Indiafor electricity in India

40000

50000

60000

70000

80000

90000

100000

110000

120000

IN M

W -

-->

1990-91 1991-92 1992-93 1993-94 1994-95 1995-96 1996-97 1997-98 1998-99 1999-00 2000-01 2001-02 2002-03 2003-04YEARS --->

93

Kolar

Chintamani

Cudappah

HoodyHosur

Salem

Udumalpet

Madras B’lore

+/- 500 KV DC line 1370 KM

ElectrodeStation

ElectrodeStation

TALCHER

400kv System

220kv system

KOLAR

TALCHER KOLAR TALCHER KOLAR SCHEMATICSCHEMATIC

94

Inter Regional Links

Present IR CapacityPresent IR Capacity= 9,000 MW= 9,000 MW

700 MW700 MW

1200MW1200MW

2000MW2000MW

700 MW700 MW

900 MW900 MW30,500 MW

16,000

32,700 MW

30,500 MW

2300

1850 MW1850 MW

1650 MW1650 MW

95

13450 MW

1000 MW6450 MW

4600 MW

1300 MW3200 MW

30,000 MW OF INTER-REGIONAL POWER BY 2012

EASTERN REGION

SOUTHERN REGION

WESTERNREGION

NORTHERN REGION


INTER-REGIONAL TRANSFER BY INTER-REGIONAL TRANSFER BY END OF 11END OF 11thth PLAN (2012) PLAN (2012)

96

RESERVOIR LEVEL - COMPARISONRESERVOIR LEVEL - COMPARISON

LEVEL IN MTSLEVEL IN MTS LEVELLEVEL31-Dec-0331-Dec-03

LEVELLEVEL31-Dec-0431-Dec-04

JALAPUTJALAPUT837.21837.21 834.94834.94

LINGANMAKKILINGANMAKKI543.84543.84 547.16547.16

SUPASUPA532.42532.42 537.86537.86

IDUKKIIDUKKI713.96713.96 720.27720.27

KAKKIKAKKI967.40967.40 969.29969.29

NILGIRISNILGIRIS

TOTALTOTAL

ENERGYENERGY31-Dec-0331-Dec-03

ENERGYENERGY31-Dec-0431-Dec-04

RISE IN MURISE IN MU % RISE% RISE

484484 390390 - 9494 - 1919

18611861 25302530 669669 3636

945945 12301230 285285 3030

847847 12291229 382382 4545

485485 531531 4646 99

546546 13581358 812812 149149

51685168 72687268 21002100 4141

• Only 6500MUs Reserve till next monsoon (5 Months)

• 43 MUs/day could be generated as against about 63 MUs/day at present.

97

320

330

340

350

360

370

380

390

400

410

42000

:05

01:0

5

02:0

5

03:0

5

04:0

5

05:0

5

06:0

5

07:0

5

08:0

5

09:0

5

10:0

5

11:0

5

12:0

5

13:0

5

14:0

5

15:0

5

16:0

5

17:0

5

18:0

5

19:0

5

20:0

5

21:0

5

22:0

5

23:0

5

TIME IN HRS --->

VO

LT

AG

E IN

KV

---

>

REALITY BITE:

FARMERS IN KARNATAKA ARE HAPPY WITH FEWER HOURS OF QUALITY POWER!!.

EFFICIENCY OF PUMPS AT TG HALLI WATER WORKS IMPROVED!

COMPARISION OF BANGALORE VOLTAGE-TYPICAL DAY

BETTER VOLTAGE PROFILE MEANS LESS ELECTRICAL LOSSES

98

WATER SUPPLY TO BANGALORE

LOW VOLTAGE PROBLEMS AROUND BANGALORE HAMPERED WATER SUPPLY EARLIER

WITH BETTER VOLTAGE NOW, PUMPING EFFICIENCY HAS IMPROVED

400 KV STATION AT MYSORE BEING COMMISSIONED ON WAR FOOTING TO FURTHER FORTIFY THIS PART OF THE GRID

PUMPING LOSSES REDUCED

ENORMOUS SAVINGS TO THE STATE

MOTOR BURNING AND MAINTENANCE COSTS ALSO CAME DOWN DRASTICALLY

99

FREQUENCY CURVE FOR 9th SEPTEMBER 2004FVI = 0.04

Avg Freq = 49.99Hz

48.5

49.0

49.5

50.0

50.5

51.0

00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23

10 * ∑ (F – 50) 2

FVI = -------------------------------

24 * 60

100

Sector wise consumption of Sector wise consumption of electricity in India in 2002-electricity in India in 2002-

20032003

24%

25%

7%34%

7%

3%

IndustryDomesticRailwaysAgricultureCommercialOthers

101

Hydro Thermal mix in India Hydro Thermal mix in India in 2004in 2004

26%4%

70%

ThermalHydroNuclear+Wind

102

THANK YOU

presentation on frequency control and

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