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

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Project Scope Introduction Literature Search Simulation Software Requirements Data Collection and Analysis System Description System Impact Studies Conclusions Future Work

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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. Engineering analysis requires detailed simulation models.

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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 4

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 – IEEE Std. 519-1992

 Islanding – UL 1741 – IEC 62116 5

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 • Identifies limitations in the industry practice of integrating PV facility into the distribution grid, and further proffers an approach to improve PV interconnection (2011) studies • Investigates impact of high PV penetration level on an existing network as a case study

Report IEA- • Investigates voltage rises due to PV penetration and possible mitigation measures (Ota City demonstration project - Japan) PVPS T1006-2009 • Investigates reasons for power imbalances between phases of a solar settlement (PV settlement of “Schlierber” - Germany).

F. Katiraei • Documents and reviews the results from several field experiments, measurements, and system studies performed at International Energy Agency Photovoltaic Power Systems (2007)

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. 6

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 Networks and Mini-Grids,” International Journal of Distributed Energy Resources, Vol. 3, No. 3, July – September 2007

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EPRI’s Work Lots of case studies for lots of feeders Relatively low PV penetration levels Did not investigate imbalance in great detail

Reference: J. Smith, “PV Modeling for Distribution System Impact Assessment Using the OpenDSS,” Utility/Lab Workshop on PV Technology and Systems, November 8-9, 2010

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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? Reference: NREL, “Southern California Edison High-Penetration Photovoltaic Project – Year 1,” Technical Report, N REL/TP-5500-50875, June 2011

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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 10

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What are the issues? Category

Issue

Overcurrent protection get “confused” -> false trips, no trips Line regulators get “confused -> high/low voltage on DG side Capacitor switching, LTC operation, and line VR operation caused by cloud shading. Voltage Fluctuation Flicker caused by step voltage change during switching. Capacitor switching transients (synchronous closing, preinsertion impedance, point-on-wave) Low/medium PV penetration -> PV offsets load thereby decreasing section loading Modification of Feeder Section Loading 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 Fault Current PV increases fault current. Impact on relay protection. Utility system reclosing into live island may damage Unintentional Islanding switchgear and loads. Ground Fault Overvoltage Single-phase fault -> TOVs on unfaulted phase. Harmonics Harmonics caused by PV inverter Effect of fast transients caused by cloud shading and system Dynamics disturbances. Dynamic interaction of transients with other conventional and non-conventional control devices. Imbalance caused by uneven distribution of PV causing Feeder Imbalance Neutral-to-Earth voltages, Overloaded Neutrals Reverse Power Flow

OpenDSS PSCAD

EMTPRV

X X X X

X

X

X

X

X

X

X

X

X

X

X

X X

X

X 12

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Load Profiles

Residential and Commercial Load Profiles from Manitoba Hydro Southern California Edison Hydro One

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Manitoba Hydro: Residential

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Manitoba Hydro: Commercial

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Manitoba Hydro: Summary Residential Unit Size

Min Load (kW)

Under 1000 1000-1500 1500-2000 2000-2500 Over 2500

0.5 3.2 2.4 2.1 3.4

Max Load (kW) 15.1 10.9 17.4 29.2 38.2

Max. Down- Max. Up-Ramp Ramp (kW/h) (kW/h) -6.8 -4.9 -7.6 -10.2 -22.4

8.4 3.7 6.2 14.9 27.2

Consumption (MWh) 38.4 52.4 67.4 77.3 94.6

Commercial Type Drive-Through Restaurants Shopping Mall Generic Grocery Grocery Store Superstore

Min Load (kW)

Max Load (kW)

64.6 48.6 1,658.3 207.0 495.4 1,748.9

523.0 197.7 7,392.6 459.2 1,092.8 4,071.4

Max. DownRamp (kW/h) -162.5 -44.2 -1,724.1 -81.5 -209.8 -787.5

Max. Up-Ramp (kW/h) 186.8 51.2 1,457.0 106.7 169.8 629.9

Consumption (MWh) 1,753.1 776.7 32,832.3 2,957.9 6,502.6 24,779.1

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Generation Profiles

PV Generation Profiles from Manitoba Hydro (Winnipeg) Southern California Edison (Long Beach) Hydro One (Toronto) BC Hydro (Vancouver)

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PV Variation (Months) Manitoba Hydro

BC Hydro

Hydro One

Southern California Edison

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PV Variation (Hours and Seconds)

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Net Zero Scenario

Annual consumption matches annual local PV generation Building does not need outside power IF perfect storage available

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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

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Shingles Scenario

Thin-film photovoltaic shingles produce between 50 and 200 watts A roof of an average household is assumed to fit about 3 kW

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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 – Primary circuit miles: 30.5 25

Feeder Systems (continued)

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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

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Load Distribution – Hydro One  Load profiles Distribution

Phase A B C

Average Load (kW) Eastern Connection 13.76 10.90 12.98

Central Connection Western Connection 10.88 10.95 12.61 13.61 10.96 10.86 28

Net Zero– Hydro One  Scaling factors

Phase A B C

Average PVNetZero (kW) Eastern Connection 53.03 41.97 52.43

Central Connection Western Connection 41.54 41.87 49.13 52.18 44.41 44.35 29

Financial Net Zero– Hydro One  Scaling factors

Phase A B C

Average PVFinancial (kW) Eastern Connection 5.01 3.94 5.00

Central Connection Western Connection 3.93 3.96 4.65 4.93 4.22 4.13 30

Shingles – Manitoba Hydro  Scaling factors

 Average kW per customer Phase A B C

Average PVShingles (kW) Eastern Connection 1.94 0.85 3.01

Central Connection Western Connection 1.48 1.50 0.99 1.07 2.61 2.58 31

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Cases - Daily Case

Phase with PV

Case #

DescriptionScenario

Season

PV Profile

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 12

A, B, C A, B, C

100% Consumption Net Zero 100% Consumption Net Zero

Summer Winter

Note: for Fall, Summer & Winter the day with the biggest generation-consumption ratio was used

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Cases – Daily (continued)  Seasonal simulation cases 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

 Used parameters – Installed PV Capacity in kW Location Manitoba Hydro

NetZero (kW) A B C 5,874 4,885 6,622

Financial (kW) A B C ----

Shingles (kW) A B C 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

--

--

--

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Case 1: Hydro One - Primary  Snapshot during hour with highest solar activity

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Case 1: Hydro One - Primary

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Case 1: Hydro One - Primary  Voltage (p.u.) Eastern Connection Phase A B C

Max 1.036 1.037 1.034

No PV Min 1.029 1.029 1.021

Diff 0.008 0.008 0.013

Max 1.044 1.043 1.039

With PV Min 1.023 1.017 1.015

Diff 0.020 0.026 0.023

Max 1.046 1.040 1.019

With PV Min 1.023 1.017 1.007

Diff 0.023 0.023 0.012

With PV Min 1.023 1.017 1.015

Diff 0.02 0.026 0.023

 Voltage (p.u.) Central Connection Phase A B C

Max 1.036 1.037 1.034

No PV Min 1.031 1.027 1.029

Diff 0.005 0.010 0.005

 Voltage (p.u.) Western Connection Phase A B C

Max 1.036 1.037 1.034

No PV Min 1.029 1.029 1.021

Diff 0.008 0.008 0.013

Max 1.044 1.043 1.039

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Case 1: Hydro One – Secondary  Snapshot during hour with highest solar activity

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Case 1: Hydro One – Secondary

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Case 1: Hydro One – Secondary  Voltage (p.u.) Eastern Connection Phase A B C

Max 1.032 1.032 1.024

No PV Min 1.018 1.018 1.007

Diff 0.014 0.013 0.016

Max 1.075 1.078 1.080

With PV Min 1.035 1.028 1.033

Diff 0.039 0.050 0.046

Max 1.069 1.112 1.052

With PV Min 1.036 1.028 1.014

Diff 0.033 0.084 0.038

With PV Min 1.036 1.028 1.019

Diff 0.047 0.053 0.041

 Voltage (p.u.) Central Connection Phase A B C

Max 1.032 1.032 1.028

No PV Min 1.023 1.009 1.017

Diff 0.010 0.023 0.011

 Voltage (p.u.) Western Connection Phase A B C

Max 1.032 1.032 1.028

No PV Min 1.020 1.017 1.014

Diff 0.012 0.015 0.014

Max 1.083 1.081 1.061

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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

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Annually: Hydro One - Primary

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Annually: Hydro One - Secondary

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Annually: Hydro One  Primary Connection

Cycles above 1.05

Cycles below 0.95

Eastern

# of Buses (All Phases) 246

0

17

Central

126

0

2

Western

267

0

269

Cycles above 1.05

Cycles below 0.95

Eastern

# of Buses (All Phases) 177

10466

1

Central

203

23692

2

Western

281

25930

2

 Secondary Connection

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Cases – Unsymmetrical Penetration  Simplified system

 Adjusted parameters:  Transformer connection (i.e. D-Y, D-D, Y-D, and Y-Y)  Line length (i.e. 5 km, 10 km, and 20 km)  Load imbalance severity (i.e. Imbalance Load Factor: 2, 4 and 8) 45

Unsymmetrical Penetration Line Length Imbalance Scenario (km) Factor 1 10 2 2 1 4 3 1 2 4 5 2 5 10 2 6 20 2 7 5 -2 8 10 -2 9 20 -2 10 1 2 11 1 4 12 1 8 13 1 -2 14 1 -4 15 1 -8

Phase A Phase B Phase C Load (kW) Load (kW) Load (kW) Impact Evaluated 341.6 170.8 170.8 683.2 170.8 170.8 Transformer Connection 341.6 170.8 170.8 341.6 170.8 170.8 Line length for positive 341.6 170.8 170.8 imbalance loading factor 341.6 170.8 170.8 -341.6 170.8 170.8 Line length for negative -341.6 170.8 170.8 imbalance loading factor -341.6 170.8 170.8 341.6 170.8 170.8 Load imbalance severity 683.2 170.8 170.8 for positive imbalance 1,366.4 170.8 170.8 loading factor -341.6 170.8 170.8 Load imbalance severity -683.2 170.8 170.8 for negative imbalance -1,366.4 170.8 170.8 loading factor 46

Transformer Connection

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Line Length  Positive imbalance factor

 Negative imbalance factor

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Load Imbalance Severity  Positive imbalance factor

 Negative imbalance factor

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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) Load1 Z1

PV1

V1 Load2

Z2

PV2

V2 Load3

Z3

V3

PV3 50

Secondary Network 1. No PV

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Cases – Secondary Network 2. With PV – no mitigations

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

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

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Project No. T114700-5097 Solar Power Variability Impacts on the Distribution System

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Solar Power Variability Impacts

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

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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

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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 65

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.

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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 – Providing telemetry capability for the unit – Providing diagnostics of the units “health” 67

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

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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. 69

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 70

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