BAL-001-TRE-1 Primary Frequency Response in the ERCOT Region Overview Jan 10, 2014 Future Ancillary Service Team Workshop By: Sydney Niemeyer – NRG Energy

BAL-001-TRE-1

Primary Frequency Response in the ERCOT RegionOverview Jan 10, 2014

Future Ancillary Service Team WorkshopBy: Sydney Niemeyer – NRG Energy

Requirements 1 & 2

• Identify and post events that will be measured.

• Measure each generator’s performance.

R3.The BA shall calculate the Interconnection minimum Frequency Response (IMFR) in December of each year for the following year, and make the IMFR, the methodology for calculation and the criteria for determination of the IMFR publicly available.

M3. The BA shall demonstrate that the IMFR was calculated in December of each year per Requirement R3. The BA shall demonstrate that the IMFR, the methodology for calculation and the criteria for determination of the IMFR are publicly available.

Requirements 3 – 5: Maintain Interconnection Frequency Response

R4.

The BA shall determine and make publicly available the Interconnection’s combined Frequency Response performance for a rolling average of the last six (6) FMEs by the end of the following month.

M4.

The BA shall provide evidence that the rolling average of the Interconnection’s combined Frequency Response performance for the last six (6) FMEs was calculated and made public per Requirement R4.


R5.Following any FME that causes the Interconnection’s six-FME rolling average combined Frequency Response performance to be less than the IMFR, the BA shall direct any necessary actions to improve Frequency Response, which may include, but are not limited to, directing adjustment of Governor deadband and/or droop settings.

M5. The BA shall provide evidence that actions were taken to improve the

Interconnection’s Frequency Response if the Interconnection’s six-FME rolling average combined Frequency Response performance was less than the IMFR, per Requirement R5..


ERCOT Primary Frequency Response – BAL-003-12014 Bias and Frequency Response Measure Page 1

Date/Time (t-0) BA BA BA Relay Lmt Value "A" Information Value "B" Information SEFRD (FRM)Time Bias R1 for Bias for R1

BA Time Zone DelFreq Time DelFreq DelFreq MW/Load Lost Adjustment MW/Load Lost Adjustment (MW/0.1Hz) (MW/0.1Hz)

12/10/2012 12:32:54 CST -0.076 12:32:54 -0.076 -0.076 0.0 0.0 790.9 0.0 -1042.1 -1042.1

12/12/2012 7:31:10 CST -0.093 7:31:10 -0.093 -0.093 0.0 0.0 641.6 0.0 -690.4 -690.4

12/25/2012 4:30:20 CST -0.134 4:30:20 -0.134 -0.134 0.0 0.0 912.6 100.0 -604.5 -604.5

1/2/2013 14:41:26 CST -0.134 14:41:26 -0.134 -0.134 0.0 0.0 827.4 0.0 -618.9 -618.9

1/13/2013 20:35:06 CST -0.111 20:35:06 -0.111 -0.111 0.0 0.0 810.1 0.0 -730.6 -730.6

1/15/2013 10:04:14 CST -0.158 10:04:14 -0.158 -0.158 0.0 0.0 740.0 0.0 -468.5 -468.5

1/19/2013 23:10:16 CST -0.088 23:10:16 -0.088 -0.088 0.0 0.0 714.6 0.0 -816.1 -816.1

1/22/2013 16:06:24 CST -0.076 16:06:24 -0.076 -0.076 0.0 0.0 857.0 80.0 -1028.7 -1028.7

3/4/2013 21:47:48 CST -0.146 21:47:48 -0.146 -0.146 0.0 0.0 595.0 0.0 -406.8 -406.8

3/7/2013 17:05:56 CST -0.085 17:05:56 -0.085 -0.085 0.0 0.0 781.1 0.0 -914.0 -914.0

3/15/2013 18:39:50 CDT -0.086 18:39:50 -0.086 -0.086 0.0 0.0 528.9 0.0 -615.2 -615.2

3/18/2013 17:21:22 CDT -0.082 17:21:22 -0.082 -0.082 0.0 0.0 494.6 0.0 -603.8 -603.8

4/2/2013 21:25:34 CDT -0.098 21:25:34 -0.098 -0.098 0.0 0.0 758.2 0.0 -770.3 -770.3

4/9/2013 18:21:40 CDT -0.073 18:21:40 -0.073 -0.073 0.0 0.0 758.5 0.0 -1037.2 -1037.2

4/23/2013 11:19:30 CDT -0.063 11:19:30 -0.063 -0.063 0.0 0.0 469.1 0.0 -739.1 -739.1

4/29/2013 13:59:14 CDT -0.126 13:59:14 -0.126 -0.126 0.0 0.0 522.1 0.0 -413.1 -413.1

5/7/2013 3:07:26 CDT -0.120 3:07:26 -0.120 -0.120 0.0 0.0 504.8 0.0 -422.1 -422.1

5/11/2013 20:13:48 CDT -0.089 20:13:48 -0.089 -0.089 0.0 0.0 392.0 0.0 -438.8 -438.8

5/17/2013 13:38:22 CDT -0.052 13:38:22 -0.052 -0.052 0.0 0.0 473.1 0.0 -902.7 -902.7

5/22/2013 16:11:30 CDT -0.151 16:11:30 -0.151 -0.151 0.0 0.0 846.0 0.0 -559.6 -559.6

5/29/2013 23:47:34 CDT -0.109 23:47:34 -0.109 -0.109 0.0 0.0 716.3 0.0 -655.6 -655.6

5/30/2013 14:46:22 CDT -0.125 14:46:20 -0.125 -0.125 0.0 0.0 784.2 0.0 -629.5 -629.5

6/4/2013 18:04:26 CDT -0.094 18:04:26 -0.094 -0.094 0.0 0.0 606.4 0.0 -644.8 -644.8

6/11/2013 10:56:36 CDT -0.146 10:56:36 -0.146 -0.146 0.0 0.0 910.0 0.0 -625.0 -625.0

6/12/2013 19:45:22 CDT -0.128 19:45:22 -0.128 -0.128 0.0 0.0 825.4 0.0 -642.4 -642.4

6/25/2013 18:47:46 CDT -0.075 18:47:46 -0.075 -0.075 0.0 0.0 451.0 0.0 -601.5 -601.5

6/26/2013 23:09:56 CDT -0.119 23:09:56 -0.119 -0.119 0.0 0.0 804.4 0.0 -675.2 -675.2

7/21/2013 18:00:50 CDT -0.119 18:00:50 -0.119 -0.119 0.0 0.0 599.2 0.0 -501.9 -501.9

ERCOT Primary Frequency Response – BAL-003-12014 Bias and Frequency Response Measure – Page 2

Date/Time (t-0) BA BA BA Relay Lmt Value "A" Information Value "B" Information SEFRD (FRM)Time Bias R1 for Bias for R1

BA Time Zone DelFreq Time DelFreq DelFreq MW/Load Lost Adjustment MW/Load Lost Adjustment (MW/0.1Hz) (MW/0.1Hz)

7/21/2013 18:00:50 CDT -0.119 18:00:50 -0.119 -0.119 0.0 0.0 599.2 0.0 -501.9 -501.9

7/25/2013 1:15:52 CDT -0.087 1:15:52 -0.087 -0.087 0.0 0.0 827.3 0.0 -953.4 -953.4

8/2/2013 15:35:08 CDT -0.122 15:35:08 -0.122 -0.122 0.0 0.0 916.6 0.0 -753.2 -753.2

8/11/2013 5:43:36 CDT -0.104 5:43:36 -0.104 -0.104 0.0 0.0 827.5 0.0 -792.1 -792.1

8/12/2013 2:58:06 CDT -0.075 2:58:06 -0.075 -0.075 0.0 0.0 783.3 0.0 -1045.3 -1045.3

8/18/2013 16:45:34 CDT -0.108 16:45:34 -0.108 -0.108 0.0 0.0 605.8 0.0 -562.6 -562.6

8/20/2013 14:19:12 CDT -0.084 14:19:12 -0.084 -0.084 0.0 0.0 601.4 0.0 -719.5 -719.5

8/24/2013 18:46:10 CDT -0.082 18:46:10 -0.082 -0.082 0.0 0.0 563.1 0.0 -689.3 -689.3

8/29/2013 18:55:24 CDT -0.059 18:55:24 -0.059 -0.059 0.0 0.0 804.4 0.0 -1360.4 -1360.4

9/25/2013 9:17:30 CDT -0.103 9:17:30 -0.103 -0.103 0.0 0.0 717.8 0.0 -698.9 -698.9

10/8/2013 11:56:08 CDT -0.071 11:56:08 -0.071 -0.071 0.0 0.0 460.8 0.0 -647.3 -647.3

10/12/2013 20:23:26 CDT -0.059 20:23:26 -0.059 -0.059 0.0 0.0 547.9 0.0 -921.5 -921.5

11/1/2013 21:47:32 CDT -0.104 21:47:32 -0.104 -0.104 0.0 0.0 1286.6 420.0 -829.8 -829.8

11/12/2013 16:34:04 CST -0.080 16:34:04 -0.080 -0.080 0.0 0.0 449.9 0.0 -561.2 -561.2

11/14/2013 2:39:02 CST -0.104 2:39:02 -0.104 -0.104 0.0 0.0 779.0 0.0 -748.3 -748.3

11/14/2013 11:01:54 CST -0.059 11:01:54 -0.059 -0.059 0.0 0.0 496.0 0.0 -836.8 -836.8

11/22/2013 16:23:46 CST -0.087 16:23:46 -0.087 -0.087 0.0 0.0 506.0 0.0 -578.5 -578.5

11/26/2013 14:07:10 CST -0.053 14:07:10 -0.053 -0.053 0.0 0.0 533.0 0.0 -1002.7 -1002.7

11/27/2013 6:16:20 CST -0.119 6:16:20 -0.119 -0.119 0.0 0.0 853.5 0.0 -720.0 -720.0

-722.16 2013 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1

-657.55 2013 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1

-689.89 2013 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response

R6.Each GO shall set its Governor parameters as follows:

R6.1. Limit Governor dead-bands within those listed in Table 6.1, unless directed otherwise by the BA.

M6. Each GO shall have evidence that it set its Governor parameters in accordance with Requirement R6. Examples of evidence include but are not limited to: •Governor test reports•Governor setting sheets•Performance monitoring reports

M6.1 The GO shall have evidence that it set the Governor dead-bands as required in Table 6.1 in Requirement R6.

Generator Type Max. Dead-band

Steam and Hydro Turbines with Mechanical Governors +/- 0.034 Hz

All Other Generating Units/Generating Facilities +/- 0.017 Hz

Table 6.1 Governor Deadband Settings

Generator Type Max. Droop % Setting

Hydro 5%

Nuclear 5%

Coal and Lignite 5%

Combustion Turbine (Simple Cycle and Single-Shaft Combined Cycle) 5%

Combustion Turbine (Combined Cycle) 4%

Steam Turbine (Simple Cycle) 5%

Steam Turbine (Combined Cycle)* 5%

Diesel 5%

Wind Powered Generator 5%

DC Tie Providing Ancillary Services 5%

Renewable (Non-Hydro) 5%

R6.2 Limit Governor droop settings such that they do not exceed those listed in Table 6.2, unless directed otherwise by the BA.

Table 6.2 Governor Droop Settings

For digital and electronic Governors, once frequency deviation has exceeded the Governor dead-band from 60.000 Hz, the Governor setting shall follow the slope derived from the formula below.

where MWGCS is the maximum megawatt control range of the Governor control system. For mechanical Governors, droop will be proportional from the dead-band by design.

Proportional Droop From The Dead-band

Requirements 7 & 8

• Operate with governor in service.– When on-line and released for dispatch.

• Report when governor out of service.

R9 & R10• Generator Performance measure for Initial response.

Measures response during 20 to 52 seconds after the the beginning of the event.– Uses ERCOT data. Time period allows for some data delay and

time to deliver response.• Generator Performance measure for Sustained response.

Utilizes the frequency value at 46 seconds after the beginning of the event and measures generator’s best response during the 46 to 60 second time period.

• Measures utilize Per Unit scaling, Actual Response divided by Expected Response with minimum compliance of 0.75 P.U. rolling monthly average on both measures.

450

455

460

465

470

475

480

485

490

59.8

59.82

59.84

59.86

59.88

59.9

59.92

59.94

59.96

59.98

60

60.02

60.04

60.06

60.08

60.1

20:34:06 20:34:16 20:34:26 20:34:36 20:34:46 20:34:56 20:35:06 20:35:16 20:35:26 20:35:36 20:35:46 20:35:56 20:36:06

MW

Fre

qu

ency

Hz

Example A

Frequency Avg Frequency Freq @ t(+46)

Example A MW EPFRI Final ESPFR(Final@t(+46)

1.3531.378

Primary Frequency Response Evaluation - Initial(0.75 P.U. or higher = Passing) -Sustained

23.47 17.3524.17 17.54

P.U. Act MW Exp MW1/13/13

Pre-event Frequency

Pre-event Average MW

Initial Measure “R9” Expected Primary Frequency Response

“EPFR”

Sustained Measure “R10” Expected Primary Frequency

Response “EPFR”

Frequency @ t(+46) for “Sustained” measure R10.

Event Average Frequency for the “Initial” measure R9.

495

500

505

510

515

520

525

530

59.8

59.82

59.84

59.86

59.88

59.9

59.92

59.94

59.96

59.98

60

60.02

60.04

60.06

60.08

60.1

20:34:06 20:34:16 20:34:26 20:34:36 20:34:46 20:34:56 20:35:06 20:35:16 20:35:26 20:35:36 20:35:46 20:35:56 20:36:06

MW

Fre

qu

ency

Hz

Example B

Frequency Avg Frequency Freq @ t(+46)

Example B MW EPFRI Final ESPFR(Final@t(+46)

1.0911.082


16.96 15.5517.06 15.76


510

513

516

519

522

525

528

531

534

537

540

543

546

549

552

555

59.74

59.76

59.78

59.8

59.82

59.84

59.86

59.88

59.9

59.92

59.94

59.96

59.98

60

60.02

60.04

16:02:54 16:03:04 16:03:14 16:03:24 16:03:34 16:03:44 16:03:54 16:04:04 16:04:14 16:04:24 16:04:34 16:04:44 16:04:54

MW

Fre

qu

ency

Hz

Generator X

Frequency Avg Frequency Freq @ t(+46) MW EPFRI Final ESPFR(Final@t(+46)

1.1671.295


59.90Up Margin MW 20.98 17.9720.57 15.88-287.10


500

506

512

518

524

530

536

542

548

554

560

566

572

578

584

590

59.8

59.82

59.84

59.86

59.88

59.9

59.92

59.94

59.96

59.98

60

60.02

60.04

60.06

60.08

60.1

15:50 15:55 16:00 16:05 16:10 16:15 16:20 16:25 16:30 16:35 16:40 16:45 16:50

MW

Fre

qu

ency

Hz

Generator X

Frequency MW HSL LSL

1.167

1.295Primary Frequency Response Evaluation - Initial

(0.75 P.U. or higher = Passing) -Sustained59.90Up Margin MW 20.98 17.97

20.57 15.88-287.10P.U. Act MW Exp MW

When the generator is in a down ramp at the time of the event, the post event performance will be impacted by the AGC sent to the generator that the generator has yet to deliver. The BAL-001-TRE measurements adjust for this pre-event down ramp.

Adjustments To Measures

• Steam Turbines:– Initial inlet pressure less than rated pressure.

• If a generator slides pressure, response will be less. Adjustment compensates for the reduced pressure.

– Steam Flow adjustment.• At outputs greater than 50%, backpressure due to

steam already flowing through the turbine, additional steam flow has resistance to increase flow. This is small reduction in expected performance.

– For flows less than 50%, the adjustment increases the expected performance.

Adjustments To Measures

• Steam Turbines:– The change in inlet steam pressure caused by

“responding” to the change in frequency reduces the expected response.

• Combustion Turbines:– The change in mass flow through the turbine

caused by the change in grid frequency (turbine speed) reduces the expected response.

BAL-001-TRE

• R9 & R10 Compliance– Based on average performance of past 12 months

with a minimum of 8 event participation. If fewer than 8 events are measured in 12 months, the time period continues until 8 events are measured.

• Some infrequently used generators will never get measured.• Generator must have a minimum of 5 MW or 2% of HSL

margin to be measured during an event.• Increases the importance of keeping the HSL accurate as

possible.

0.000

0.500

1.000

1.500

2.000

2.500

0 10 20 30 40 50 60 70

Example A

Event Initial P.U. Score Event Sustained P.U. Score

34Number of Events

1.308

1.38

Per Unit "Initial" average

Per Unit "Sustained" average performance:

Generator either “Off Line”, below LSL or less than 5 MW or 2% margin during these events. If the generator with margin responded in the wrong direction, the minimum P.U. score is zero.

0.000

0.500

1.000

1.500

2.000

2.500

0 10 20 30 40 50 60 70

Example B


22Number of Events

1.091

1.18



0.000

0.500

1.000

1.500

2.000

2.500

0 10 20 30 40 50 60 70

Example C


21Number of Events

0.952

1.02



0.000

0.500

1.000

1.500

2.000

2.500

0 10 20 30 40 50 60 70

Example D


25Number of Events

1.000

1.19



Equipment limits during events can result in low measures. The rolling 12 month average reduces the need to adjust for these events.

0.000

0.500

1.000

1.500

2.000

2.500

0 10 20 30 40 50 60 70

Example CCx


15Number of Events

1.083

1.38



0.000

0.500

1.000

1.500

2.000

2.500

0 10 20 30 40 50 60 70

Example SCGTx


15Number of Events

1.457

1.51



Summary

• All generators participate equally.– Each generator has to do less with full

participation.• Measures are designed to account for known

limitations of delivery of Primary Frequency Response.

• Properly implemented, each generator should easily meet the minimum performance requirements.

Documents

BAL-001-TRE-1 Primary Frequency Response in the ERCOT Region Overview Jan 10, 2014 Future Ancillary Service Team Workshop By: Sydney Niemeyer – NRG Energy