grid management aspect of renewables - rmel...grid management aspect of renewables. sandip sharma...

GRID MANAGEMENT ASPECT OF RENEWABLES

Sandip Sharma Manager, Operations Planning ERCOT RMEL 2019 Spring Conference May 20 – 22, 2019 Phoenix, Arizona

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Outlines

• Background information of ERCOT • Renewable Integration Practices and Solutions at ERCOT

– Grid Code – Forecasting – Ancillary Services – Risk Assessment – Real-Time Operations

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What is ERCOT?

The Texas Legislature restructured the Texas electric market in 1999 and assigned ERCOT four primary responsibilities: • System Reliability • Competitive Wholesale

Market • Open Access to

Transmission • Competitive Retail Market

ERCOT is a nonprofit organization and regulated by the Public Utility Commission of Texas, with oversight by the Texas Legislature. ERCOT is not a market participant and does not own generation or transmission/distribution wires.

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Current Records

Peak Demand Record: 73,473 megawatts (MW) • July 19, 2018, 4-5 p.m.

Weekend Peak Demand Record: 71,445 MW • Sunday, July 22, 2018, 5-6 p.m.

Winter Peak Demand Record: 65,915 MW • Jan. 17, 2018, 7-8 a.m.

Wind Generation Records (instantaneous) • Output: 19,672 MW

‒ Jan. 21, 2019, 7:19 p.m.

• Penetration (load served): 56.16% ‒ January 19, 2019, 3:10 a.m. ‒ Total MW Served by Wind = 17,406 MW

Recent Monthly Peak Demand Records 2019 • March: 60,692 MW (March 5, 7-8 a.m.) 2018 • January: 65,915 MW (Jan. 17, 7-8 a.m.)

• May: 67,265 MW (May 29, 4-5 p.m.)

• June: 69,123 MW (June 27, 4-5 p.m.)

• July: 73,473 MW (July 19, 4-5 p.m.)

• November: 56,317 MW (Nov. 14, 7-8 a.m.)

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Changing Resource Capacity Mix

Late 1990s 2018

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Utility Scale Solar Generation Capacity – March 2019

Future outcomes uncertain

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Utility Scale Solar Generation Capacity – March 2019

Future outcomes uncertain

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Outlines

• Background information of ERCOT • Renewable Integration Practices and Solutions at ERCOT

– Grid Code – Forecasting – Ancillary Services – Risk Assessment – Real-Time Operations

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Renewable Integration at ERCOT

1. Grid Code 2. Renewable Forecast

3. Ancillary Services

4. Risk Assessment

5. Real-time Operations

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IRR (Intermittent Renewable Resources)

Frequency Response (governor actions)

Reactive Capability

and Voltage Ride-through

Ramp Rate Limitation

Short Circuit Ratio

Secondary Frequency Response

Primary Frequency Response

Large Wind Ramp

Interconnection Requirements

System Impacts

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Integrating Renewables – Frequency Control

• All generation in ERCOT is required to provide governor response with a 5% droop setting with a deadband of 17 mHZ.

• Renewable resources started to assist in frequency control (by having an automatic response to frequency deviations) after 2010. – NERC’s BAL-001-TRE regional standard was implemented starting April 1,

2015. This reduced Governor Dead-band for most resources including renewables from 36 mHz to 17 mHZ.

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Voltage Ride-through Requirements

• Renewable resources that interconnected after 2008 are required to ride through i.e. stay online during abnormal disturbances in voltage and frequency.

No Tripping

00.10.20.30.40.50.60.70.80.91.01.11.2

-1 0 1 2

Volta

ge (p

er u

nit)

@ P

OI

0.15(9 cycles)

Pre-fault Period Voltage Recovery Period

Fault Clearing Period

Time (Seconds)

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Ramp Rate Limitation

• Renewable resources that were installed after 2009 are required to implement controls which limit per minute ramping to 20% of the unit’s nameplate rating.

6.5.7.10 Intermittent Renewable Resource Ramp Rate Limitations 1) Each Intermittent Renewable Resource (IRR) that is part of a Standard Generation Interconnection

Agreement (SGIA) signed on or after January 1, 2009 shall limit its ramp rate to 20% per minute of its nameplate rating (MWs) as registered with ERCOT when responding to or released from an ERCOT deployment.

2) The requirement of paragraph (1) above does not apply during a Force Majeure Event or during intervals in which a decremental deployment instruction coincides with a demonstrated decrease in the available IRR.

3) Each IRR that is part of an SGIA signed on or before December 31, 2008 and that controls power output by means other than turbine stoppage shall limit its ramp rate to 20% per minute of its nameplate rating (MWs) as registered with ERCOT when responding to or released from an ERCOT deployment.

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4. Risk Assessment


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Wind Forecasting at ERCOT

WIND GENERATION RESOURCE (WGR)

• Asset Registration

Information

• Outage/De-rate Schedule

• Real Time Telemetry

WIND FORECAST SERVICE

• Two Forecast Service

Providers each provide:

• Hourly Forecast for each WGR for each hour of next week, updated hourly

• Intra-hour Forecast for

next 2-hr, at 5-min resolution, updated every 15-min

• Extreme Event Forecasts and Probabilistic Forecasts, used for risk assessment

ERCOT SYSTEMS

• ERCOT Control Room can select “active forecast” for every hour and every 5-min.

• Hourly Forecast Used in all Look Ahead Studies (ex. Outage Coordination, Reliability Unit Commitment, Next Day Study)

• Intra-hour Forecast To be used in Real Time Dispatch

• Extreme Event Forecasts and Probabilistic Forecasts, used for risk assessment

* WGR Operators can reduce the Current Operating Plan (COP) High Sustained Limit (HSL) to reflect operating condition changes.

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Wind Forecast Errors (Day-Ahead)

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Wind Forecast Errors (Hour-Ahead)

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PVGR Forecast Errors (Day-Ahead)

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PVGR Forecast Errors (Hour-Ahead)

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4. Risk Assessment


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• SCED sends dispatch instruction every 5 minutes.

• LFC sends Regulation signals to generation resources every 4 second service to move up or down to maintain frequency at nominal.

Ancillary Services – Regulation Service

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Wind Installation Capacity (MW) vs. Averaged Hourly Reg-up Requirement

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Wind Installation Capacity (MW) vs. Monthly CPS1

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Ancillary Services – Non-Spinning Reserve Service (NSRS) • Non-spinning Reserve Service

– 30 minute product that can be provided by unloaded capacity, offline Generators, and Load Resources

– Wind power and load forecast error is one of the inputs used for calculating the requirement for this service

– The net forecast error uncertainty that NSRS will be used to mitigate will depend on the risk of net load ramp.

– During higher net load ramp risk hours, we procure NSRS to cover up to 95th percentile of net forecast uncertainty.

– During low net load ramp risk hours, we may only procure NSRS to cover 70th percentile of net forecast uncertainty.

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Minimum NSRS Requirement in 2019

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Ancillary Services – Responsive Reserves

• Responsive Reserves are procured to ensure sufficient capacity is available to respond to frequency excursions due to unit trips ‒ Capacity reserved from generators to provide governor response

‒ Up to 60% of Responsive requirement can be provided by Load

Resources on under-frequency relays (to trip when frequency decreases to 59.7 Hz for .5s) once minimum 1150 MW has been procured from Generators proving PFR

• Since 2015, the Responsive Reserve procurement is based on

expected system inertia.

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Inertial Effect

Initial rate of change of frequency (prior to any resource response) is solely a function of inertia

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Frequency Response Times

• Load Resources providing RRS have underfrequency relays that respond in about 0.5s after the frequency drops below the trigger level (currently 59.7Hz)

• Governors of thermal generating units begin to respond “immediately” but will take 1-3 seconds to provide significant response (requires more steam or more combustion)

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Current RRS Studies

Case1 Case2 Case 3 Case4 Case5 Case6 Case7 Case8 Case9 Case10 Case11 Case12 Case13 Case14 Case15 Case16

Inertia (GW∙s) 130 140 150 160 170 180 190 200 220 230 260 270 290 300 359 376

LRs/PFR 2.39:1 2.17:1 1.85:1 1.85:1 2.00:1 1.71:1 1.53:1 1.43:1 1.55:1 1.30:1 1.10:1 1.10:1 1.00:1 1.20:1 1.00:1 0.89:1

PFR Requirement

(No LRs) 5691 5056 4388 4295 4550 3972 3445 3224 3475 2970 2745 2580 2450 2650 2300 2085

PFR min 1150 1150 1150 1150 1150 1150 1150 1150 1150 1150 1150 1150 1150 1150 1150 1150

LRs 1900 1800 1750 1700 1700 1650 1500 1450 1500 1400 1450 1300 1300 1250 1150 1050

Combined Total 3050 2950 2900 2850 2850 2800 2650 2600 2650 2550 2600 2450 2450 2400 2300 2200

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Minimum RRS Requirement (MW) in 2019

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4. Risk Assessment


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RRS Sufficiency Monitoring

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Capacity Availability Tool (CAT)

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4. Risk Assessment


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Real Time System Wide Wind Generation Curtailment

0

100

200

300

400

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700

800

4000

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5000

5500

6000

6500

7000

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

Win

d C

urta

ilmen

t (M

W)

Win

d G

ener

atio

n (M

W)

Hour

Base Point Telemetry MW HDL Curtailment MW

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Real Time - Individual Wind Generation Curtailment

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164

166

168

170

172

174

176

178

180

59.85

59.875

59.9

59.925

59.95

59.975

60

60.025

60.05

13:25 13:28 13:31 13:34 13:37 13:40

WIND RESOURCE RESPONSE TO LOW FREQUENCY 07/13/2016

Frequency Nominal Frequency MW


• Renewable resources started to assist in frequency control (by having an automatic response to frequency deviations) after 2010.

80

90

100

110

120

130

140

59.925

59.944

59.963

59.981

60.000

60.019

60.038

60.056

60.075

16:13 16:16 16:19 16:22 16:25 16:28

WIND RESOURCE RESPONSE TO HIGH FREQUENCY 08/25/2015

Frequency Nominal Frequency MW

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Questions?

grid management aspect of renewables - rmel...grid management aspect of renewables. sandip sharma...

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