1

PDCWG Report to ROS

October 13, 2011

Sydney Niemeyer

2

ERCOT Frequency Control Performance

September, 2011

3

ERCOT CPS1 By Day -

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Day

NE

RC

CP

S 1

0

3500

7000

10500

14000

17500

21000

24500

28000

31500

35000

38500

42000

45500

49000

52500

56000

59500

63000

66500

70000

ER

CO

T P

eak

En

erg

y

CPS 1 Avg CPS 1 Peak Energy

September-2011

152.34ERCOT Monthly CPS1 =

4

ERCOT CPS1 15 Minute Average - Monthly Score

0

20

40

60

80

100

120

140

160

180

200

0:15

1:15

2:15

3:15

4:15

5:15

6:15

7:15

8:15

9:15

10:1

511

:1512

:1513

:1514

:1515

:1516

:1517

:1518

:1519

:1520

:1521

:1522

:1523

:15

Interval Ending

September-2011 152.34CPS 1 =

5

ERCOT CPS1

100

110

120

130

140

150

160

170

CP

S1

Ave

rag

e

100

110

120

130

140

150

160

170

Monthly Average 12 Month Rolling Average

6

Daily RMS1 of ERCOT Frequency

0.0100

0.0150

0.0200

0.0250

0.0300

0.0350

0.0400

0.0450

0.0500

7

Daily RMS1 of ERCOT Frequency

0.0100

0.0150

0.0200

0.0250

0.0300

0.0350

0.0400

0.0450

0.0500

1/1/

2004

4/1/

2004

7/1/

2004

10/1

/200

4

1/1/

2005

4/1/

2005

7/1/

2005

10/1

/200

5

1/1/

2006

4/1/

2006

7/1/

2006

10/1

/200

6

1/1/

2007

4/1/

2007

7/1/

2007

10/1

/200

7

1/1/

2008

4/1/

2008

7/1/

2008

10/1

/200

8

1/1/

2009

4/1/

2009

7/1/

2009

10/1

/200

9

1/1/

2010

4/1/

2010

7/1/

2010

10/1

/201

0

1/1/

2011

4/1/

2011

7/1/

2011

8

Daily RMS1 of ERCOT Frequency

0.0100

0.0150

0.0200

0.0250

0.0300

0.0350

0.0400

0.0450

0.0500

9

Comparing September 2010 vs September 2011 profile of frequency in 5 mHz bins

0

0.02

0.04

0.06

0.08

0.1

0.12

59.9

00

59.9

10

59.9

20

59.9

30

59.9

40

59.9

50

59.9

60

59.9

70

59.9

80

59.9

90

60.0

00

60.0

10

60.0

20

60.0

30

60.0

40

60.0

50

60.0

60

60.0

70

60.0

80

60.0

90

60.1

00

Sep-10

Sep-11

10

ERCOT Total Energy

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

35,000,000

40,000,000

45,000,000

MW

H

2008 2009 2010 2011

11

ERCOT Total Energy from Wind Generation

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

MW

H

2008 2009 2010 2011

12

ERCOT % Energy from Wind Generation

0.00%

2.00%

4.00%

6.00%

8.00%

10.00%

12.00%

14.00%

Janu

ary

Febru

ary

Mar

chApr

ilM

ayJu

ne July

Augus

t

Septe

mbe

r

Octob

er

Novem

ber

Decem

ber

2008 2009 2010 2011

13

NERC Frequency Response Field Trial

14

NERC BAL-003 Field Trial

• Sets Interconnection minimum frequency response.– Goal to prevent activation of UFLS for the

largest N-2 event 2750 MW.– Present recommendation for Texas is

minimum of -286 MW/0.1 Hz measured at Point B.

• 2750 – 1150 = 1600 MW/(-0.600 x 10) = -266 MW/0.1 Hz.

15

September 28, 2011 PDCWG Open Meeting

• Review of 20% limit of RRS based on Generator Capacity (HSL).

• Discussed history of limit.– Primary Frequency Response (Droop) of 5% will

cause the Governor to move 20% of the output of the generator with a -0.600 Hz change in frequency.

– Distributes reserves on multiple generators to improve Interconnection frequency response and deliverability of reserves.

– 80% loading point on traditional steam turbines had the lowest average heat rate.

16

Historical Performance

• May 15, 2003 event where frequency declined to 59.261 Hz.– From 60.012 to 59.297 in 4.5 seconds.– How much energy can a traditional generator

deliver in 4.5 seconds?• 1511 MW from turbines.• 475 MW from load dampening.• 471 MW from LaaR• 979 MW from Firm Load. (first event)

17

Today: Increased Load Resources and More Turbine Response

– How much energy can a traditional generator deliver in 4.5 seconds?

• 1811 MW from turbines (for same 3434 MW loss)• 475 MW from load dampening.• 1150 MW from LaaR• 0 MW from Firm Load

– For 2750 MW event instead of 3434 MW• 1127 MW from turbines.

18

-600

-540

-480

-420

-360

-300

-240

-180

-120

-60

0

59.30

59.35

59.40

59.45

59.50

59.55

59.60

59.65

59.70

59.75

59.80

59.85

59.90

59.95

60.00

60.05

60.10

MW

/0.1

Hz

Pri

mar

y F

req

uen

cy R

esp

on

se

Fre

qu

ency

-H

z

Frequency Hz Average FrequencyInterconnection Primary Frequency Response Interconnection Average Primary Frequency Response

Thursday, May 15, 20033434

-1450

1984

Total MW Lost

MW Net Loss to Grid

NCLR Tripped or non-conforming load change

-356.9 Average Interconnection Primary Frequency Response MW/0.1 Hz

59.3130

59.4521

60.0124

-356.9-283.7 MW/0.1 Hz MW/0.1 Hz 59.09% of Bias Setting

Primary Frequency Response at Point C

Primary Frequency Response at Point B average

May 15, 2003 Actual Performance

19

59.2

59.3

59.4

59.5

59.6

59.7

59.8

59.9

60

60.1

-10 -9 -8 -7 -6 -5 -4 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26

Seconds

Hz

-0.3

-0.25

-0.2

-0.15

-0.1

-0.05

0

0.05

0.1

Hz/

seco

nd

Frequency Hz/sec Change

-0.268 Hz/second maximum rate of change.

Resources MW Loss 3434 12.34%

-0.000078043 Max Hz/second/MW Loss

of Total Energy

of Peak Energy

of Total Energy

Total Spinning MW

Total Energy MW 27806 45.65%

13265 47.71%May 15, 2003 02:53

20

If the % of RRS Was Changed

RRS 1150 Supplied by GeneratorsPresent

Limit 20%10% 18% 20% 22% 30% 40% 50% Percent of Generator Capacity allowed for RRS

RRS Generator MW Capacity 11500 6389 5750 5349 3833 2875 2300

Expected PFR @ 5% droop -383.3 -213.0 -191.7 -178.3 -127.8 -95.8 -76.7

59.7 59.46 59.4 59.355 59.1 58.8 58.5

Minimum Generator Capacity required to provide service.MW/0.1 Hz from Minimum Generator Capacity measured at the B Value (Point B settling frequency).

Frequency (Hz) required to move the turbine governor the maximum percentage of RRS on the generator.

Expected Primary Frequency Response from RRS

providers if all capacity is frequency responsive.

21

What FERC wants: loss of two largest generators interconnected at a single switchyard and not trip UFLS.n-2 2750 Simultaneous trip of two largest generators (STP 1 & 2)

RRS Supplied by Load Resources 1150 Trips at 59.700 Hz in one half second.

Remaining MW loss 1600

These MWs must be replaced by turbine frequency response and load dampening of synchronous motors. Worse case would be 344 MW from load dampening and 1256 MW from generators in about 4 seconds.

Frequency Response (MW/0.1 Hz) req for -228.571 59.3 Hz Minimum FrequencyFrequency Response (MW/0.1 Hz) req for -266.667 59.4 Hz Minimum Frequency

Winter peak will be around -73 MW/0.1 Hz since resistive heat load is not frequency responsive.

Load Dampening ranges from -53 MW/0.1 Hz at ERCOT minimum load of 22,000 MW to -166 MW/0.1 Hz at summer peak of 68,294 MW.

Highest risk of UFLS tripping is during the shoulder months, light load periods when the electrical mass of the grid is lowest and frequency moves fastest.

To Prevent UFLS

22

Is 20% the Right Amount?

• Increasing % allowed to be provided by a single Resource would decrease PFR.– Increase risk of UFLS.– Governor can not move Gen full % before UFLS.

• Decreasing % allowed to be provided by a single Resource would increase PFR.– Decrease risk of UFLS.– Easier for Generator to perform.

• No change in %. Continue effort to improve PFR from RRS providers.– Continue to expect PFR from all spinning reserve and

improve their performance.

23

Find Other Sources of PFR

• Short duration, fast response (less than 4 seconds) would decrease the risk of UFLS.– Storage– Flywheel

• Create a Product for this service.

24

Recent Frequency Response Performance

25

-1000.0

-900.0

-800.0

-700.0

-600.0

-500.0

-400.0

-300.0

-200.0

-100.0

0.0

12/0

6/10

11:

25:0

0

12/1

1/10

22:

38:1

8

12/1

6/10

06:

15:0

8

12/1

9/10

02:

39:0

0

12/2

3/10

14:

41:4

2

12/2

6/10

08:

32:0

2

01/1

1/11

06:

50:1

4

01/2

1/11

03:

46:2

8

01/2

8/11

05:

21:4

4

02/0

1/11

22:

27:4

8

02/0

2/11

05:

14:1

8

02/0

2/11

08:

24:3

0

02/0

9/11

13:

01:3

8

02/1

6/11

09:

25:4

0

03/1

4/11

06:

09:3

4

03/1

6/11

20:

45:0

8

03/2

4/11

13:

59:0

6

03/2

9/11

06:

43:0

8

04/0

5/11

22:

02:0

6

04/2

7/11

23:

27:0

6

05/1

6/11

08:

06:3

8

05/2

0/11

19:

34:5

5

05/2

3/11

17:

34:4

0

06/0

1/11

03:

56:3

1

06/0

9/11

14:

17:2

2

06/2

7/11

12:

54:0

2

06/2

7/11

14:

38:2

7

07/1

8/11

09:

13:1

6

07/2

0/11

19:

17:2

4

07/2

5/11

17:

57:1

2

08/0

4/11

12:

55:2

1

08/3

1/11

21:

36:3

2

09/0

4/11

10:

12:0

0

09/1

9/11

01:

35:0

0

MW

/0.1

Hz

ERCOT System Primary Frequency Response - Dec 2010 thru Jul 2011

Point C

B Value w/o LaaRs

-386.1

-545.583.54%

MW/0.1 Hz @ Pt C

of Bias Setting (Pt B)MW/0.1 Hz @ Pt B

Average Performance

26

-1200

-1140

-1080

-1020

-960

-900

-840

-780

-720

-660

-600

-540

-480

-420

-360

-300

-240

-180

-120

-60

0

59.70

59.72

59.74

59.76

59.78

59.80

59.82

59.84

59.86

59.88

59.90

59.92

59.94

59.96

59.98

60.00

60.02

60.04

60.06

60.08

60.10

MW

/0.1

Hz

Pri

mar

y F

req

uen

cy R

esp

on

se

Fre

qu

ency

-H

z

Frequency Hz Average FrequencyInterconnection Primary Frequency Response Interconnection Average Primary Frequency Response

Monday, September 19, 2011830.6

0

830.6

Total MW Lost

MW Net Loss to Grid

NCLR Tripped or non-conforming load change

-602.7 Average Interconnection Primary Frequency Response MW/0.1 Hz

59.7530

59.8393

59.9779 -602.7-369.4 MW/0.1 Hz MW/0.1 Hz 92.58% of Bias Setting

Primary Frequency Response at Point C

Primary Frequency Response at Point B average

27

-0.100

-0.080

-0.060

-0.040

-0.020

0.000

0.020

59.60

59.65

59.70

59.75

59.80

59.85

59.90

59.95

60.00

Frequency Rate of Change

830.6Resource MW Loss

of Peak Energy

of Total Energy

Total Spinning MW

Total Energy MWof Energy

of GenerationTotal Wind Generation MW

Max Hz/second/MW Loss

31383

0.013 -0.000097520

5.56%

22.62%

47.76%

2.65%

1745

7100

-0.081 Hz/second

Hz/second

9/19/2011 1:35

Higher frequency rate of change per MW tripped than the May 15, 2003 event.

28

PDCWG On-going Work

• Continue review of Generator’s Primary Frequency Response Performance.– Contacting low performers to help improve

performance.– Observed PFR from two wind farms during

minor high frequency following unit trips.

• Continue effort to review protocols and guides to clarify PFR and RRS responsibilities.