The Impact of Solar Power and Other Variable Distributed Renewable Generation on the Distribution Grid

The Impact of Solar Power and Other

Variable Distributed Renewable

Generation on the Distribution Grid

Jenna Van Vliet, Hydro Ottawa Frank Chan, CEATI International Robyn Pascal, CEATI International

Project Scope



Introduction



Literature Search



Simulation Software Requirements



Data Collection and Analysis



System Description



System Impact Studies



Conclusions



Future Work

Introduction



Penetration of PV generation in distribution and

transmission systems has increased dramatically

in recent years.



Small numbers of PV generation offer few or

no problems, but as the percentage of PV

generation grows, a number of issues begin to

appear.



Large penetrations of PV generators might have

negative impacts on the system they are connected

to.

Pertinent Standards

IEEE Std. 1547-2003: Standard for Interconnecting Distributed Resources with Electric Power Systems

– IEEE Std. 1547.1-2005: Test Procedures for Interconnection Equipment – IEEE Std. 1547.2-2008: Application Guide for IEEE Std 1547

– IEEE Std. 1547.3-2007: Monitoring, Information Exchange, and Control – IEEE Std. 1547.4-2011: Design, Operation, and Integration Island

Systems

Under Development:

– IEEE Std. 1547.5: Power Sources Greater than 10MVA (Transmission

Grid)

– IEEE Std. 1547.6-2011: Secondary Networks

– IEEE Std. 1547.7: Distribution Impact Studies for Distributed Resource

Interconnection

– IEEE Std. 1547.8: Implementation Strategies for Expanded Use of

IEEE Standard 1547

Other Applicable Standards



Flicker

– IEEE Std. 1453-2004

– IEC Std. 61000-3-3, -3-5, -3-7, and -4-15



Voltage Regulation Requirements

– ANSI C84.1 – CAN3-C235



Harmonics



Islanding

Previous Work

Study Summary

Ropp (2008) • Reviews potential problems and utility concerns arising from high penetration levels of

photovoltaic in distribution systems

J. W. Smith (2011)

• Identifies limitations in the industry practice of integrating PV facility into the distribution grid, and further proffers an approach to improve PV interconnection studies

• Investigates impact of high PV penetration level on an existing network as a case study

Report IEA-PVPS

T10-06-2009

• Investigates voltage rises due to PV penetration and possible mitigation measures (Ota City demonstration project - Japan)

• Investigates reasons for power imbalances between phases of a solar settlement (PV settlement of “Schlierber” - Germany).

F. Katiraei (2007)

• Documents and reviews the results from several field experiments, measurements, and system studies performed at International Energy Agency Photovoltaic Power Systems projects in some IEA participating countries

• Covers power quality effects, voltage issues of high PV penetration and planning/design requirements to mitigate these effects

J. Widen (2009)

• Discusses limiting factors of distributed PV systems in Swedish energy system, using a simulation approach.

IEA Report published in 2007



_{Penetration levels less than 7%}



Reviewed field experience in

– Japan (Gunma)

– Germany (Schlierberg)

– Australia (Olymp. Village)

– Netherlands (Nieuwland)

– Greek Islands

Reference:

F. Katiraei, K. Mauch, L. Dignard-Bailey, “Integration of Photovoltaic Power Systems in High-Penetration Clusters for Distribution

EPRI’s Work

Lots of case studies for lots of feeders

Relatively low PV penetration levels

Did not investigate imbalance in great detail

November 8-9, 2010 Reference:

J. Smith,

“PV Modeling for Distribution System Impact Assessment Using the OpenDSS,” Utility/Lab Workshop on PV Technology and Systems,

NREL’s (National Renewable Energy Laboratory) Work



_{Three criteria dictating}

penetration limits

– Fault current sensitivity

– Reverse power

– Voltage/overload restrictions

– DER Penetration Limits Application



_{Our questions}

– Is it really that simple?

– How about imbalance?

Effects of PV on Utility Operation

Potential issues and concerns associated with

increased PV generation in power systems. Effects on:



Overcurrent protection coordination



Voltage regulation



Reliability



Power losses



Detection of unintentional islanding



Overvoltage during islanding



Voltage change during DG tripping

What are the issues?

12

Category Issue OpenDSS PSCAD

EMTP-RV Reverse Power Flow Overcurrent protection get “confused” -> false trips, no trips X

Line regulators get “confused -> high/low voltage on DG side X

Voltage Fluctuation

Capacitor switching, LTC operation, and line VR operation

caused by cloud shading. X

Flicker caused by step voltage change during switching. X X Capacitor switching transients (synchronous closing,

pre-insertion impedance, point-on-wave) X X

Modification of Feeder Section Loading

Low/medium PV penetration -> PV offsets load thereby decreasing section loading

X High PV penetration -> PV may exceed base load, capacity

sufficient to distribute surplus power?

Increase in Power Losses PV changes loading (see row above). Impact on losses X

Fault Current PV increases fault current. Impact on relay protection. X X Unintentional Islanding Utility system reclosing into live island may damage

switchgear and loads. X X

Ground Fault Overvoltage Single-phase fault -> TOVs on unfaulted phase. X X

Harmonics Harmonics caused by PV inverter X

Dynamics

Effect of fast transients caused by cloud shading and system disturbances. Dynamic interaction of transients with other conventional and non-conventional control devices.

X X

Feeder Imbalance Imbalance caused by uneven distribution of PV causing

Load Profiles

Residential and Commercial Load Profiles

from



Manitoba Hydro



_{Southern California Edison}



_{Hydro One}

Manitoba Hydro: Commercial

Manitoba Hydro: Summary

Residential

Commercial

Unit Size Min Load (kW) Max Load (kW) Max. Down-Ramp (kW/h) Max. Up-Ramp (kW/h) Consumption (MWh) Under 1000 0.5 15.1 -6.8 8.4 38.4 1000-1500 3.2 10.9 -4.9 3.7 52.4 1500-2000 2.4 17.4 -7.6 6.2 67.4 2000-2500 2.1 29.2 -10.2 14.9 77.3 Over 2500 3.4 38.2 -22.4 27.2 94.6

Type Min Load (kW) Max Load (kW) Max. Down-Ramp (kW/h) Max. Up-Ramp (kW/h) Consumption (MWh) Drive-Through 64.6 523.0 -162.5 186.8 1,753.1 Restaurants 48.6 197.7 -44.2 51.2 776.7 Shopping Mall 1,658.3 7,392.6 -1,724.1 1,457.0 32,832.3 Generic Grocery 207.0 459.2 -81.5 106.7 2,957.9 Grocery Store 495.4 1,092.8 -209.8 169.8 6,502.6 Superstore 1,748.9 4,071.4 -787.5 629.9 24,779.1

Generation Profiles

PV Generation Profiles from



Manitoba Hydro (Winnipeg)



_{Southern California Edison (Long Beach)}



Hydro One (Toronto)



_{BC Hydro (Vancouver)}

PV Variation (Months)

Manitoba Hydro Hydro One

PV Variation (Hours and Seconds)

Net Zero Scenario



_{Annual consumption matches annual local PV}

generation



Building does not need outside power IF perfect

Financial Net Zero Scenario



_{Annual consumption cost matches annual cost of}

the electricity generated by a solar PV system



Building does not need outside power IF perfect

storage available

Shingles Scenario



_{Thin-film photovoltaic shingles produce between}

50 and 200 watts



A roof of an average household is assumed to fit

Feeder Systems



_{Initial simulation on IEEE 34-bus test feeder}



_{More detailed simulation on modified EPRI}

Test circuit

– System Voltage: 12.47 kV

– Number of Customers: 1379

– Service XFMR kVA: 16310

– Total feeder kVAr: 1950

Feeder Systems (continued)

Load Distribution



Customer load profiles were integrated into the test feeder

by substituting the original loads



To provide reasonable comparison between the three

resulting systems, the total loading of the phases was kept

constant



Number of customers connected to a specific service

transformer resulted from the respective customer’s

maximum annual demand

Load Distribution – Hydro One

 Load profiles Distribution

Phase Average Load (kW)

Eastern Connection Central Connection Western Connection

A 13.76 10.88 10.95

B 10.90 12.61 13.61

C 12.98 10.96 10.86

Net Zero– Hydro One

 Scaling factors

Phase Average PV_NetZero (kW)

Eastern Connection Central Connection Western Connection

Financial Net Zero– Hydro One

 Scaling factors

Phase Average PV_Financial (kW)

Eastern Connection Central Connection Western Connection

A 5.01 3.93 3.96

B 3.94 4.65 4.93

C 5.00 4.22 4.13

Shingles – Manitoba Hydro

 Scaling factors

 Average kW per customer

Phase Average PV_Shingles (kW)

Eastern Connection Central Connection Western Connection

Cases - Daily

Case # Description PV Profile

Case Phase with PV Scenario Season

1 A, B, C 100% Consumption Net Zero Spring

2 B 100% Consumption Net Zero Spring

3 A, B, C Shingles (MH & SCE) Spring

Financial Net Zero (HO) Spring

4 A, B, C 25% Consumption Net Zero Spring

5 A, B, C 50% Consumption Net Zero Spring

6 A, B, C 75% Consumption Net Zero Spring

7 A, B 100% Consumption Net Zero Spring

8 A, C 100% Consumption Net Zero Spring

9 B, C 100% Consumption Net Zero Spring

10 A, B, C 100% Consumption Net Zero Fall

11 A, B, C 100% Consumption Net Zero Summer

Cases – Daily (continued)

 Seasonal simulation cases

 Used parameters – Installed PV Capacity in kW

Location Spring Summer Fall Winter

Manitoba Hydro Mar. 15 Jun. 7 Sep. 14 Feb. 5

SCE Apr. 4 Jul. 4 Sep. 19 Feb. 13

Hydro One May 1 Jun. 4 Sep. 28 Feb. 19

Location NetZero (kW) Financial (kW) Shingles (kW)

A B C A B C A B C

Manitoba Hydro 5,874 4,885 6,622 -- -- -- 321 201 545

SCE 6,072 7,061 4,695 -- -- -- 2,727 248 3,276

Hydro One 8,920 9,882 9,354 843 934 888 -- --

Case 1: Hydro One - Primary

Case 1: Hydro One - Primary

Case 1: Hydro One - Primary

 Voltage (p.u.) Eastern Connection

 Voltage (p.u.) Central Connection

 Voltage (p.u.) Western Connection

Phase No PV With PV

Max Min Diff Max Min Diff

A 1.036 1.029 0.008 1.044 1.023 0.020

B 1.037 1.029 0.008 1.043 1.017 0.026

C 1.034 1.021 0.013 1.039 1.015 0.023

Phase No PV With PV

Max Min Diff Max Min Diff

A 1.036 1.031 0.005 1.046 1.023 0.023

B 1.037 1.027 0.010 1.040 1.017 0.023

C 1.034 1.029 0.005 1.019 1.007 0.012

Phase No PV With PV

Max Min Diff Max Min Diff

Case 1: Hydro One – Secondary

 Snapshot during hour with highest solar activity

Case 1: Hydro One – Secondary

 Voltage (p.u.) Eastern Connection

 Voltage (p.u.) Central Connection

 Voltage (p.u.) Western Connection

Phase No PV With PV

Max Min Diff Max Min Diff

A 1.032 1.018 0.014 1.075 1.035 0.039

B 1.032 1.018 0.013 1.078 1.028 0.050

C 1.024 1.007 0.016 1.080 1.033 0.046

Phase No PV With PV

Max Min Diff Max Min Diff

A 1.032 1.023 0.010 1.069 1.036 0.033

B 1.032 1.009 0.023 1.112 1.028 0.084

C 1.028 1.017 0.011 1.052 1.014 0.038

Phase No PV With PV

Max Min Diff Max Min Diff

A 1.032 1.020 0.012 1.083 1.036 0.047

B 1.032 1.017 0.015 1.081 1.028 0.053

Cases - Annually



PV penetration – Net Zero



Simulation duration – 8760 hours



_{The obtained results provide an estimate over the}

number of times the feeder voltage cycles above

1.05 pu and below 0.95 pu

Annually: Hydro One - Primary

Annually: Hydro One

 Primary

 Secondary

Connection # of Buses (All Phases)

Cycles above 1.05 Cycles below 0.95

Eastern 177 10466 1

Central 203 23692 2

Western 281 25930 2

Connection # of Buses (All Phases)

Cycles above 1.05 Cycles below 0.95

Eastern 246 0 17

Central 126 0 2

Western 267 0 269

Cases – Unsymmetrical Penetration

 Simplified system

 Adjusted parameters:

 Transformer connection (i.e. D-Y, D-D, Y-D, and Y-Y)

Unsymmetrical Penetration

Load (kW) Impact Evaluated 1 10 2 341.6 170.8 170.8

Transformer Connection 2 1 4 683.2 170.8 170.8

3 1 2 341.6 170.8 170.8 4 5 2 341.6 170.8 170.8

Line length for positive imbalance loading factor 5 10 2 341.6 170.8 170.8

6 20 2 341.6 170.8 170.8 7 5 -2 -341.6 170.8 170.8

Line length for negative imbalance loading factor 8 10 -2 -341.6 170.8 170.8

9 20 -2 -341.6 170.8 170.8

10 1 2 341.6 170.8 170.8 _{Load imbalance severity} for positive imbalance loading factor

11 1 4 683.2 170.8 170.8 12 1 8 1,366.4 170.8 170.8

13 1 -2 -341.6 170.8 170.8 Load imbalance severity for negative imbalance loading factor

14 1 -4 -683.2 170.8 170.8 15 1 -8 -1,366.4 170.8 170.8

Line Length

 Positive imbalance factor

 Negative imbalance factor

Load Imbalance Severity

 Positive imbalance factor

Cases – Secondary Network

1. No PV

2. With PV – no mitigations

3. With PV – System meets IEEE Std. 1547 (tripping if phase voltage deviates from permitted range)

4. With PV – System meets IEEE Std. 1547 (controlled dump loads to consume excessive power from PV)

PV1 PV2 PV3 Load3 Load2 Load1 Z1 Z2 Z3 V1 V2 V3 50

1. No PV

Cases – Secondary Network

Cases – Secondary Network

3. With PV – System meets IEEE Std. 1547 (tripping if phase voltage deviates from permitted range)

Cases – Secondary Network

4. With PV – System meets IEEE Std. 1547 (controlled dump loads to consume excessive power from PV)

Project Summary

– Objectives: Provide a technically sound method of aggregating PV impacts on distribution feeder voltage control. Develop quantitative measures of the voltage control impacts from a variable DG source

– Builds on the UWIG DG Evaluation Toolbox – Completed Tasks

• Literature Search

• Flicker Meter Implementation in OpenDSS

• Feeder Model Reduction CYME  OpenDSS – Tasks to Do

• New Screener and PV Profile Aggregation Using Wavelets on Web Server

Solar Power Variability Impacts

Source: LBLN-2855E

Literature Search

– Little Available on Solar Variability – Background from Wind Variability – Existing Solar Results

• Focus on Ramp Rates for Transmission • Variability Can be Comparable to Wind • Small Separation  More Correlation • Small Time Windows  Less Correlation

– Selected Lave’s Wavelet Method for Use on Distribution Systems

Conclusion

 No grid today is ready for 100% penetration of PV

 Significant impact of the conductor type on coupling effects during imbalanced phase loading

 Imbalance can be much greater than expected both from coupling impacts and changes in actual load at the location of the installation

 Use of three-phase voltage regulators that do not allow for

controlling the voltage on each phase individually, and three-phase tap changers will be an issue in installation of distributed generation

 Tap changers and other voltage regulating equipment will need more frequent maintenance

Conclusion

 Voltage rises are not uniform and in many cases the voltage at the substation maybe well within limits while at other locations along the feeder, voltage limits may be violated during PV peak production.

 Power quality issues start at low penetration levels and are greatly influenced by the quality and size of the inverters used to tie the system to the grid

 With tight clustering and a poorly designed (from an acceptance of distributed generation point of view) circuit can see impacts at less than 1 percent penetration.

Recommendations

 Suggestions for amendments to current interconnection standards:

– Randomization for the wait period for restart of a unit when it has

been disconnected

– Sensing significant voltage drop that would indicate that the area has

been disconnected from the main grid

– Allowing for remote disconnect and connect

– Allowing operating parameters to be programmed into the unit

– Providing a direct DC tap off the unit to power local DC based

equipment

– Setting up inverters to create VARs on demand

– Limiting the size of inverters

Mitigation Options

 Options for mitigation in today’s regulatory and standards

environment can provide the ability to safety increased the level of distributed generation installed:

– Disconnect the DG and pay the owner for the lost potential generation

– Placement of voltage regulators

– Use of phase balancing equipment

Potential Future Phases

 Future phases of this project will:

1. extend simulation runs described in the current report to include more realistic PV scenarios, which would:

• account for high-resolution temporal variation and spatial variation of PV,

• use large variety of measured load curves rather than few aggregated averaged ones,

• estimate additional distribution equipment maintenance requirements due to high PV penetration,

• investigate harmonics and other PQ problems due to increased power electronics deployment,

• look at the detailed impacts of PV on equipment installed in the grid, and

• investigate detailed needs for new equipment to be installed to support grid operations.

Potential Future Phases

 Future phases of this project will:

2. study small wind as renewable energy source on distribution grid,

• completion of the modeling – both circuit and substation

• review of literature on small wind

• look at the impacts of small wind installations on the model circuit

• provide a report focused on small wind that covers the following

3. combine the PV and small wind models for various scenarios of Distributed Energy Resources (DER) penetration, and

4. extend DER scenarios to include storage and electric vehicle models

• Review of the impacts of storage on the distribution grid and substations

• Matrix of storage uses and characteristics of storage for each use