solar reporting plan resource... · above, inverters should recover real power as fast as possible...

Solar Reporting Plan

Jack Norris, Engineer, Performance Analysis-Data AnalyticsSeptember 20, 2017

RELIABILITY | ACCOUNTABILITY2

• Background• Steps to a Section 1600 data request GADSWG Role NERC Committees Comments and Recommendations

• GADSWG Solar Subgroup• Preliminary Schedule• Guidelines for Developing Data Requirements

Agenda


Background

• As part of NERC’s mission to ensure the reliability of the bulk power system, (BPS) NERC needs data from all types of generating resources that may have an impact on reliability

• Increasing amounts of utility-scale solar are part of the changing resource mix that may affect the reliability of the BPS

• The Planning Committee requested the GADS Working Groupsdetermine the data reporting requirements for solar data reporting, with the goal of preparing a Section 1600 data request


• GADSWG forms a subgroup to develop data reporting requirements Subgroup meets separately from GADSWG meetings to draft material for

presentation and review by the GADSWG

Subgroup creates draft of data reporting instructions document for GADSWG review

• Once data reporting requirements have been defined and consensus reached, GADSWG prepares a Section 1600 data request business case and presents to Performance Analysis Subcommittee (PAS)

GADSWG: Steps to Developing a Section 1600 Data Request


• Upon review and feedback from PAS, GADSWG leadership presents the Section 1600 business case to the Planning Committee (PC)

• Upon authorization to start the Section 1600 process by the PC, GADSWG and NERC finalize the Section 1600 data request and Data Reporting Instructions for industry comment

• NERC issues announcement to FERC and industry requesting comments on the Section 1600 data request within 45 days

NERC Committees: Role in a Section 1600 Data Request


• NERC collects comments during 45-day period

• Subgroup reviews comments received and determines action/response/resolution to each comment

• Revisions are made to Section 1600 data request and/or data reporting instructions in response to comments

• GADSWG leadership presents comments to PAS and PC for acceptance by NERC’s Board of Trustees

• Section 1600 data request is reviewed by NERC’s Board of Trustees for approval

• Upon approval, NERC begins implementation process to meet implementation recommendations

NERC and GADSWG: Comments and Recommendations


• A subgroup of the GADSWG will be created to focus on developing the data requirements for solar reporting NERC liaison for GADS Solar will be Jack Norris

• GADSWG members with experience in the development, installation, and/or operation of utility-scale solar plants are encouraged to participate Please contact [email protected] & [email protected] by October 20 to

volunteer to participate in the solar subgroup

o Reminder will be made during the GADSWG conference call on October 17

GADSWG Subgroup for Development of Solar Data Requirements

mailto:[email protected]

mailto:[email protected]


• Solar subgroup will meet outside of the GADSWG meetings, primarily by conference call, to focus discussion on defining the data requirements In-person working meetings have been scheduled for 2018o January 25, 2018 - San Diego, CAo In conjunction with GADSWG in-person meetings

– Week of April 16th at NERC, Atlanta and– September 19th and 20th at WECC, Salt Lake City

GADSWG Subgroup for Development of Solar Data Requirements – cont’d


• December 2018 – Present to PAS• March 2019 – Present to PC • May 2019 – Initiate comment period• Aug 2019 - Complete comment review/resolution• Sept 2019 – Recommendation to PAS/PC for approval• Nov 2019 – Acceptance by NERC Board of Trustees• Jan 2020 – NERC begins development of application for data

collection

Preliminary Schedule


• Data reporting instructions for solar should align with terminology and concepts of GADS reporting for conventional and wind reporting New technology-specific terms and concepts are expected for solar

• Reporting requirements should be application agnostic Should be what needs to be reported, not based on the platform used to report

the data (i.e., OATI vs. other)

• Requirements to include: Method to determine solar plant qualificationo Include when mandatory reporting begins (can be defined later in the development of data

reporting requirements)

Solar technologies and ancillary equipment attached to solar plants (e.g., batteries, inverters, etc.)

Types of data to report: plant information, performance, etc. Types of outage events to report – thresholds and/or durations that constitute a

reportable event

Guidelines for Developing Data Requirements

Reactive Control Coordination

of Inverter-based Resources

Sophie XuSeptember, 2017

Agenda

2

• Steady State Reactive Control Coordination

• Transient Reactive Control Coordination

Steady State Reactive Control

Scenario:Solar farm D-Bear, B-Bear and M-Bear share the same Point of Interconnection (POI). All three Solar farms regulate the POI voltage by their Power Plant Controller (PPCs).

3

POI PPC

PPC

PPC

Solar Farm D-Bear,

Inverters by Manufacturer G

Solar Farm B-Bear,

Inverters by Manufacturer F

Solar Farm M-Bear,

Inverters by Manufacturer S


Would the three Solar Farms coordinate on POI voltage regulation?

4

Controllers w/ faster response or narrower dead band boost and buck more frequently

Others have less chance to respond

Some resources may be over producing Q while others absorbing Q


How about everyone has the same dead band and equally fast?

5


Does the incoordination only happens between inverters?

How about the following? How do everything in red in below coordinate while controlling the same or nearby voltages?

6

Solar Farm D-Bear,


Solar Farm B-Bear,


Solar Farm M-Bear,


PPC

PPC

PPC

LTC

PPC

AVR

AVR

Shunt Capacitors

SVC


Possible solutions:

PPCs to slow down and match AVR time constant, appropriate droop

Control coordination testing

Anti-hunting control option

Centralized/aggregate reactive controller(similar to AGC, applications at pjm, BC Hydro, China, Malaysia; Voltage control practices and tools used for system voltage control of PJM, http://ieeexplore.ieee.org/document/6039666/?reload=true)

Control terminal voltage (temporary solution)

7

Solar Farm A,


Solar Farm B,


Solar Farm C,


PPC

PPC

PPC

LTC

PPC

AVR

AVR

Shunt Capacitors

SVC

http://ieeexplore.ieee.org/document/6039666/?reload=true


8

Does coordinated controls resolve everything?

Watch inverter terminal voltages!

Low terminal V leads to momentary cessation or inverter tipping


Repeating momentary cessation caused by steady state voltage regulation

10


Potential solutions:

PPC monitor terminal voltage while regulates remote voltage or similar functionality

Wider operation voltage range at inverter terminals (e.g. 0.8pu – 1.2pu)

11


Expand continuous operation zone (cont’d)

Reference

PG&E Rule 21, Voltage Ride Through Requirements https://www.pge.com/tariffs/tm2/pdf/ELEC_RULES_21.pdf

12

https://www.pge.com/tariffs/tm2/pdf/ELEC_RULES_21.pdf

Agenda

13

• Steady State Reactive Control Coordination

• Transient Reactive Control Coordination

Transient Reactive Control Coordination

Overshoot can lead to inverters tripping on post contingency over voltage

14


Oscillation could happen when inverters w/ different control gains operating in one proximity

16


Potential solutions: Transient reactive power control to slow down and mimic conventional

AVR time constant and control in reaction to transient voltage excursions

Transient real power to mimic governor control in real power recovery and response to frequency

Recommendations for Voltage Ride Through Clarification

18

Acceptable performance Undesired performance

High Voltage Condition

Low Voltage Condition

• Maintain continuous operation for POI voltage ≥ 0.45 pu


19

P & Q from rotating machine

0.63 pu

• What performance is necessary during the fault (zero voltage or extremely low voltage)?

• Reactive support? but need mitigate voltage spike after fault is cleared.

Potential solution: during the fault(very low voltage) inverters maintain the same reactive current as prior to the fault

• Should recovering/maintain real power always take priority?

• Inverters should maintain real power, except to aid in voltage recovery

• Is recovering real power as fast as possible(0.1 sec or faster) a good thing?

• If frequency recovery is not the dominant concern, a slower real power recovery(0.5 – 5 sec) can be applied to reduce transient voltage depression and help synchronous generators regain stability.

• Is the “zero voltage ride through” only refer to V=0 pu or anywhere V<0.45 pu?


20

What is the impact on system frequency performance if voltage recovery takes priority in low voltage?

• Very low voltage, such as 0pu, 0.2pu, etc., is usually contained near the fault location unless the system is at the end of voltage collapse. Inverters ceasing real current at zero or very low voltage won’t cause system frequency concerns.

NERC BAL 003

Simulation from SCE Solar Interruption Investigation

Simulation from TF’s Frequency Response Study

continuous operation (No momentary) for as least voltage ≥ 0.45 pu should be enough.

Nadir happens ~6s after loss of generation.


21

Inside the Voltage Ride Through “No Trip Zone”: – During transient voltage excursion, inverters’ reactive control should respond to abnormal

voltage quickly and provide as much as support possible to help recover POI voltage. The response time is recommended to be comparable to AVR from conventional generator.(this is to emphasize that compared to steady state voltage regulation, to support transient voltage depression the inverters should respond faster and more substantial reactive power )

– Inverters should maintain continuous operation (except for 0 or very low voltage?)– During continuous operation inverters should maintain real power, except to aid in voltage

recovery– Inverters can cease real current but provide reactive support during zero/very low voltage – Once POI voltage recovers to 0.45pu (the second lowest voltage in the “No Trip Zone”) or

above, inverters should recover real power as fast as possible with stability considerations.– Inverters’ real power recovery (ramp rate + time delay) mentioned above should be as fast as

practical ( and ≤5s), except to aid in voltage recovery– If frequency is not the dominant concern, a slower real power recovery(0.5 – 5 sec) can be

applied to reduce transient voltage depression and help synchronous generators maintain stability

Recommendations for Frequency Ride Through Clarification

Inside the Frequency Ride Through “No Trip Zone”: – Inverters shall maintain continuous operation, no momentary cessation is allowed– Inverters shall reduce real power in response to high frequency – BA and RC should encourage and incentivize inverters to increase real power in

response to low frequency – A droop of 5%, which is similar to thermal units, is recommended for inverter primary

frequency response to high or low(if available) system frequency.– The frequency response time should avoid transient frequency swings. It is

recommended to be similar to governors.

22

Recommendations for Voltage and Frequency Ride Through Clarification

Outside the “No Trip Zone” for both Voltage and Frequency Ride Through: – Inverters should stay connected and maintain continuous operation as much as

practical– When inverters are disconnected due to abnormal frequency or voltage exceeding “No

Trip Zone”, it’s recommended that automatic reconnect of the inverters is not permitted. Inverters must receive permission from system operator prior to reconnection. (This disconnect refers to inverters disconnecting themselves from feeders, not the opening of breakers on transmission)

23

Questions?

24

David Piper, P.E.Operations Planning & AnalysisSCE Grid Control Center

July 21, 2017

PV Models

1

MOMENTARY CESSATION EXAMPLE

Diagram shows the real and reactive power output of the plant, as measured by the digital fault recorder at the point of interconnection.

Most inverters shut down and remained offline for approximately 750 msThe inverters resumed normal output approximately 1.5 seconds after the fault cleared

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0

50

100

150

200

250

300

350

-4 -3 -2 -1 0 1 2 3 4 5 6

pg

qg

Simulated with WECC Master Dynamic File Data (WT4G model)

Measured Response COMPARISON OF MEASURED VS SIMULATED

REVIEW OF PV DYNAMIC MODELS

REGC_A MODEL REVIEW

5

lvpl1: LVPL* breakpointMaximum pu output at LVPL breakpointe.g. 1.22 pu (lvpl1) @ 0.9 pu voltage (brkpt)

brkpt: LVPL characteristic breakpoint voltage

Voltage point that relates to lvpl1Defines start of blocking characteristic

zerox: LVPL characteristic zero crossingVoltage at which point inverters are completely blocked

lvplsw: LVPL switchIf lvplsw=1, then LVPL is enabledIf lvplsw=0, then LVPL is disabled

rrpwr: LVPL rate rate limit (pu)Defines ramp rate of return from momentary cessation

*LVPL=Low Voltage Power Logic

REEC_A MODEL REVIEW

6

Several flags determine the plant reactive power control mode

WT4G – WIND TYPE 4 (FULL CONVERTER)

7

Legacy modelShould not be used for future interconnectionsExisting models should be replaced by 2nd generation models

ANALYSIS OF MODELS IN WECC BASECASE

8

Many PV plants are still modeled as WT4GMany PV plants have LVRT logic disabledMany PV plants are using default blocking voltages (zerox = 0.4 pu)Many PV plants are using default ramp rate limit values (rrpwr=10pu)

Resulting Impact to Studies:Before beginning analysis, the model parameters of existing PV facilities must be examined and revised (as necessary).

Questions?

9

Inverter Remediation Following Blue Cut Fire

Grid Incident

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First Solar SMA Fleet Remediation

FS US SMA FLEET (Total) Quantity MWacNumber of Inverters Updated 2,349 1679

Total Number in the Fleet 2,503 1802

% Complete 94% 93%

Over 90% of SMA Inverters in the First Solar Fleet has been remediated to meet NERC Recommendation

*All CAISO Sites Have Been Updated

NERC Recommendations: Inverters that momentarily cease output for voltages outside their continuous operating range should be configured to restore output with a delay no greater than five seconds.

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Does the SMA Remediation Work?

Field Data Indcates That Remediation Works

• On July 11th,2017 Topaz Solar Plant experienced two consecutive grid disturbances between 12:40pm and 12:50pm local time

• All SMA inverters with the exception of two had been remediated at that time

• The inverters went into momentary cessation and ramped back up to pre-fault active power generation within 5 seconds as expected

• However, the two inverters without the updates tripped off as previously observed during Blue Cut Fire Event

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Plant Rides Through Grid Fault Event (July 11th 2017)

Event 1

12:43:37 12:43:4912:46:54

12:47:02Power Unit 1 ~ 267 MW

Power Unit 2 ~ 277 MW

Event 2

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Block 9 PCS 28 Inverter A vs Inverter B

~10 Minutes

Pow

er O

utpu

t

Power from Inverter B

with Update Rides

Through Grid Event

Power from Inverter A Without

Update Trips Off with

Frequency Code 502

Time

The Update Works!

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Inverter A Response Indicates Tripping Due to Low Frequency Event

Inverter tripped during the grid event on fault code 502

Power (kW)

Freq (Hz)

Voltage (V)

Fault Code Fault Code 502

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Block 9 PCS 27 Inverter A vs Inverter BPo

wer

Out

put

Time

Power from Inverter B

Without the Update Trips Off with Frequency

Code 502 Power from Inverter A with the Update

Rides Through Grid Event (does not

experience the first event of 12.43)

~10 Minutes

The Update Works!

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GE Fleet Remediation

Fix Is Being Rolled Out

• Key Issue: DC Overcurrent Trip • Fix: Parameters updated in software to

disable DC Overcurrent at the firmware level.

• Containment rollout approved for rollout by First Solar. GE working w/ FS to schedule all sites.

• Scheduled Start Date : 26th Sept

• Expected Completion: 30th Nov

• Note that only about ~100MW of GE inverters had ceased operation momentarily in the total of 1.2 GW during the trip … so it was not considered to be a major contributor

Inverter Response Time Requirements And Data Collection

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REACTIVE POWER RESPONSE

Reactive Power response time requirementReactive power responding to a step change from inductive (absorbing) maximum tocapacitive (injecting) maximum or capacitive maximum to inductive maximum:• Delay time (td): The inverter is required to start responding respond within 100ms of receipt of command by the inverter• Rise time (tr): The inverter is required to rise from initial to 95% of the steady-state value within 500 ms of the receipt of command. • Settling time (ts): The inverter response to the command should enter thesettling band within 1000 ms of the receipt of command.• Overshoot: Allowed overshoot is 0.05 p.u• Settling band range: 0.025 p.u

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ACTIVE POWER RESPONSE

Active power response time requirementActive power responding to a step change from zero to maximum active power and/ormaximum to zero active power:• Delay time (td): The inverter is required to start the Active Power (kW) injectionwithin 200 ms of receipt of command.

• Rise time (tr): The inverter is required to rise from 0-95% of the steady-statevalue for Active Power command within 1000 ms of the receipt of command by theinverter.

• Settling time (ts): The inverter response to the PPC command should enter thesettling band within 1200 ms of the receipt of command.

• Overshoot: Allowed overshoot is 0.05 p.u

• Settling band range: 0.025 p.u

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• Data collection— Inverter Data (Monitoring, Alarms and Faults)

– FS collects all inverter data from each inverter and stores in the plant historian– Plant historian data is available for 1 year

— Inverter High Speed Data (Event, Alarm, Fault logs and data)– High Speed Data for 1000V inverters in FS fleet is stored in the inverter and collected manually

for data analysis– High Speed Data is recorded only on fault in 1000V inverters in FS fleet– High Speed Data for 1500V inverters in FS fleet is polled from each inverter and provided to the

inverter manufacturer every day– High Speed Data is recorded on fault and ride through conditions in 1500V inverters in FS fleet

— Block and Plant Meters – FS collects all data (voltage, currents, pf, kW, kVAR, KVA etc.,) from each power meter and stores

in the plant historian and available for 1 year— PMU’s (On a Project Basis)

– FS collects high speed data from the PMU’s

PLANT DATA COLLECTION

Hawaii Electric Light

July 20, 2017

Lisa Dangelmaier, Hawai’i Electric Light

[email protected]

No interconnections Minimum load ~90MW

Weekday Day peak ~145MW

Evening Peak ~180MW

Automatic Generation Control (AGC) in “flat”, or constant frequency control.

Renewable energy sources: wind, hydro, geothermal, and solar

Large amount of distributed PV (approx. 78-MW)

Frequency and voltage excursions larger and occur more often than mainland.

2

Approximately 93 MW of distributed gen connected.

Most of this is PV.

No. of Systems Size (Kw) No. of Systems Size (Kw) No. of Systems Size (Kw)

59.3/60.5 Hz Legacy 560 11,047.44 - - 560 11,047.44

57/60.5 Hz Legacy 4,409 39,618.63 47 7,367.25 4,456 46,985.88

Frequency /

Voltage Ride

though /AI 7,294 42,059.06 740 14,548.35 8,034 56,607.41

Total 12,263 92,725.14 787 21,915.60 13,050 114,640.73

Installed Pre-approved Total

• Largest conventional plant contingency for planning: 30 MW

• Amount of DG with 60.5 Hz trip: approximately 58 MW

(capacity)

• More recently installed inverters are required to ride-through

• System security highly dependent on inverter behavior

Hawaii Island

System frequency dropped to 59.3Hz following loss of Hill 6 boiler,

dip in wind and BESS battery depleting. Estimated distributed PV

production was about 20MW, of which about 5-MW (25%) is believed

to have tripped at 59.3 hz. Underfrequency loadshed then

occurred.

Four consecutive events contributed to

underfrequency load shedding (UFLS) that interrupted

power to 13,768 customers for up to 9-minutes:

Hill 6 boiler trip (19 MW)

Kamaoa Windfarm decrease in output (1.2 MW)

North Kohala Battery Energy Storage System (BESS)

battery depletion (0.8MW)

Distributed Generated PV with 59.3Hz trip setting loss

(~5 MW)

12

9:30am: Underfrequency loadshed occurred when Keahole CT-5 tripped

offline. Estimated PV production was 24-MW, of which about 3-MW (13%) is

believed to have tripped when frequency dipped below 59.3 Hz.

On Sunday, April 30, 2017, lightning caused a momentary fault on Line 6500

(Pohoiki-Kaumana) while the line served approximately 9-MW of load. System

frequency reached over 60.5 Hz due to the sudden load loss, but returned to

normal when the line auto-reclosed. There are indications that distributed PV

inverters with a 60.5 Hz trip setting tripped.

At the time of the fault, System load was 135.4MW and distributed PV production

was estimated at 6.6 MW. A load increase of approximately 2-MW was detected on

distribution circuits not served by Line 6500. Milolii FIT project power production

decreased from 888-kW to 745-kW, a decrease of 16%.

Based on calculated loads of SCADA monitored distribution circuits not served by

Line 6500, there was approximately 2-MW of load increase (Chart bottom trend,

left axis) as System frequency increased (Chart 2 top trend, right axis). This is

believed to be due to distributed PV inverters tripping offline. This was about 1/3

of PV production pre-fault.

Following decrease in load is attributed to AC motor stalls due to voltage sag

experienced around the island. Voltage alarms were received from stations as far

away as Anaehoomalu and Kapua.

A feed-in-tarriff site was producing about 888-kW when the fault occurred on Line

6500. Overall power production reduced by 16%.

This facility is intended to have an expanded ride-through of these types of events.

kW Production Change

Prior to Fault Following Fault kW %

Site 1 179 142 -37 -21%

Site 2 174 103 -71 -41%

Site 3 162 162 0 0

Site 4 188 158 -30 -16%

Site 5 185 180 -5 -3%

Overall 888 745 143 -16%

Fault occurred on 10:10 am caused the fuse on ckt 111A to blow and lost part of

the circuit load.

The fault conditions resulted in PV trip and system load increased.

And 5 minutes after system frequency returned to normal, the PV reconnected and

the system load dropped again.

The circuit 109B don’t have data , only estimated. Circuit 111A is plotted on the

right Axis.

4/12/2017 18

4/12/2017 19

4/12/2017 20

© 2016 SunPower Corporation 1© 2017 SunPower Corporation

Volt-Var, Volt-Watt, Reactive Power Priority ModelFor HECO, AIFWG

September 6, 2017

Greg Kern

Principal Power Electronics Engineer

© 2016 SunPower Corporation 2

Inverter Ratings (Limits)

• Active (real) Power Limit (Watts), PRATED

• Many Inverters, PRATED = SRATED (shown in plot)

• DER systems, Prated <= SRATED

• Apparent Power Limit (VoltAmps), SRATED

• Reactive Power Limit (VoltAmpsReactive), QRATED

• May vary among inverter manufacturers

• Current Limit (Amps), IRATED

• Not shown on plot

• Determines Min. Wire Gauge and Max. Breaker Size

• Nameplate Ratings Verified by UL +/- 10%

The Power Priority only matters when the inverter is hitting one of its operating limits

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Rea

ctiv

e P

ow

er (

pu

)

Active Power (pu)

Srated Prated Qrated


Inverter + HECO Limits

• HECO Limits (Q capability)

– Apply for P ≥ 0.20 pu

– Q limit 0.53 for PRATED > 15 kW (shown on chart)

– Q limit 0.44 for PRATED ≤ 15 kW

• PAVAIL shown on chart at 0.85 pu SRATED

• This line may also correspond to a commanded maximum power operating limit

The Inverter is not required to operate outside of the PQ Capability region

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ow

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Srated PQ Capability Prated Qrated Pavail


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Srated PQ Capability

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ow

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ow

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PQ Required Regions of Capability

CA Rule 21* HECO* P1547ALL

COMBINED

*Shown for Systems > 15kWSystems ≤ 15 kW have slightly smaller regions


Default HECO SRD 1.1 SettingsFull Power Response


Active Power Priority eliminates The low voltage VAR response At high powers

Active Power Priority, combinedWith Volt-Watt creates a very Steep VAR responsePotential for voltage instability


Voltage Rise Impact on Operating Point

1% Rise – About 10% impact5% Rise – About 44% impact

If using PoC for Voltage Sense PointNeed to design systems with LESS Voltage Rise

VRISE = 1%

VRISE = 5%

VPCC = 1.05


Default HECO SRD 1.1 SettingsFull Power Response


P1547 VV & VW SettingsFull Power Response

(Draft 7.0?)


CA Rule 21 SettingsFull Power Response


The following slides were presented to CA SIWG Aug 28, 2017


Inverter + Rule21 Limits

• Rule21 Limits (Q capability)

– Apply for P ≥ 0.20 pu

– PF limit 0.85 for PRATED > 15 kW (shown on chart)

– PF limit 0.90 for PRATED ≤ 15 kW

• PINPUT shown on chart at 0.85 pu

• This line may also correspond to a commanded maximum power operating limit

The Inverter is not required to operate outside of the Q capability region

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Rea

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Active Power (pu)

Srated Q capability Prated

Qrated Pinput


Very Steep SlopeHigh Negative GainPossible Voltage Instability


Active Power PriorityEliminates Volt Var Response at high powerwhen voltage response is expected to be needed most


Below Power Level of 95%The Power Priority Mode Does Not Affect Volt VarResponse at High VoltageFor these Rule 21 settings


CA Rule21 Conclusions

• Active Power Priority may lead to Unstable Voltage Feedback

– This is seen in the overly steep voltage response curve

– This work does not predict the magnitude or frequency of any possible instability

– J. Braslavsky, J. Ward and L. Collins, “A stability vulnerability in the interaction between Volt-VAR and Volt-Watt response functions for smart inverters,” 2015 IEEE Conference on Control Applications, September 21-23, 2015. Sydney, Australia, pp. 733-738, 2015.

• Active Power Priority eliminates Volt Var response at full power when voltage response is expected to be needed most

• Below a power level of 95%, the power priority mode does not affect VoltVar response at high voltage using default Rule 21 settings.


VPCC = 1.05

VRISE = 1%VRISE = 5%Voltage Rise

Impact on Operating Point

1% Rise – no impact5% Rise – About 58% impact

If using PoC for Voltage Sense PointNeed to design systems with lower Voltage Rise

solar reporting plan resource... · above, inverters should recover real power as fast as possible...

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