PVDGIntegration Barker

8/18/2019 PVDGIntegration Barker

1/41

Experiences in Integrating PV and

Other DG to the Power System(Radial Distribution Systems)

Prepared by:

Philip Barker

Founder and Principal EngineerNova Energy Specialists, LLC

Schenectady, NY

Phone (518) 346-9770

Website: novaenergyspecialists.com

E-Mail: [email protected]

Presented at:

Utility Wind Interest Group (UWIG)

6th Annual Distributed Wind/Solar Interconnection Workshop

February 22-24, 2012

Golden, CO1Prepared by Nova Energy Specialists, LLC


2/41

Topics

• Discussion of Distribution and Subtransmission

Factors Considered in Basic DG integration Studies

• Useful Ratios for Screening Analysis of DG Impacts

• Review of Some System Impacts:

– Voltage Issues

– Fault Current Issues

– Islanding Issues

– Ground Fault Overvoltage Issues

• Summary and Conclusions of PV Experiences

Prepared by Nova Energy Specialists, LLC 2


3/41


12.47 kV

Subtransmission Line

Substation

Transformer

LTC

DG

Distribution

Feeder

Rotating Machine orInverter based DG

Step Up

Transformer

Subtransmission

Source

Bulk

System

Reclosing and

Relay Settings

Primary Feeder

Point of Connection

(POC)

Other Substations

with Load and DG

Customer

Site Load

Adjacent

Feeders

Voltage Regulator

Discussion of

Some Factors to

Consider in DG

Integration

Regulator andLTC Settings

Capacitor

Alt. Feed

Alt. Feed

Other load and

DG scattered onfeeder

Type of

Grounding

Prime mover or

energy source

characteristics


4/41

Some Useful Penetration Ratios

for Screening Analysis

• Minimum Load to Generation Ratio(this is the annual minimum load on the relevant power system section

divided by the aggregate DG capacity on the power system section)

• Stiffness Factor (the available utility fault current divided by DGrated output current in the affected area)

• Fault Ratio Factor (also called SCCR)(available utility fault current divided by DG fault contribution in the

affected area) (Note: also called Short Circuit Contribution Ratio: SCCR)

• Ground Source Impedance Ratio (ratio of zerosequence impedance of DG ground source relative to utility ground source

impedance at point of connection)

NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

Note: all ratios above are based on the aggregate DG sources on the system area of interest where appropriate



5/41

Minimum Load to Generation Ratio

(MLGR)

• Try to use the annual minimum load (don’t

just assume 1 week of measurements gives

the minimum)


Time (up to 1 year is ideal)

Minimum

Load

Peak Load

Weekend

Weekdays

Annual Minimum Load

False Minimum


6/41

Name of

Ratio What is Ratio useful for?(Note: these ratios are intended for distribution and

subtransmission system impacts of DG for the types of impacts

described below.)

Suggested Penetration Level Ratios(1)

Very Low

Penetration(Very low probability

of any issues)

Moderate

Penetration(Low to minor probability

of issues)

Higher

Penetration(4) (Increased probability

of serious issues.

Minimum

Load to

Generation

Ratio

[MLGR](2)

• MLGR used for Ground Fault

Overvoltage Suppression Analysis(use ratios shown when DG is not effectively

grounded)

>10Synchronous Gen.

10 to 5Synchronous Gen.

Less than 5Synchronous Gen.

>6Inverters(3)

6 to 3Inverters(3)

Less than 3Inverters(3)

• MLGR used for Islanding Analysis(use ratios 50% larger than shown when

minimum load characteristics are not well

defined or if significant load dropout is a

concern during sags.)

>4 4 to 2 Less than 2

Notes:1. Ratios are meant as guides for radial 4-wire multigrounded neutral distribution system DG applications and are calculated based on aggregate DG on relevant power system sections

2. “Minimum load” is the lowest annual load on the line section of interest (up to the nearest applicable protective device). Presence of power factor correction banks that result in a surplus

of VARs on the “islanded line section of interest” may require slightly higher ratios than shown to be sure overvoltage is sufficiently suppressed.

3. Inverters are inherently weaker sources than rotating machines therefore this is why a smaller ratio is shown for them than rotating machines4. If DG application falls in this “higher penetration” category it means some system upgrades/adjustments are likely needed to avoid power system issues.


Some Helpful Screening Thresholds

the Author Uses in His Studies



7/41

Type of

Ratio What is it useful for?(Note: these ratios are intended for distribution and

subtransmission system impacts of DG for the types of

impacts described below.)

Suggested Penetration Level Ratios(1)

Very Low

Penetration(Very low probability

of any issues)

Moderate

Penetration(Low to minor probability

of issues)

Higher

Penetration(3) (Increased probability

of serious issues.

Fault RatioFactor

(ISCUtility/ISCDG)

• Overcurrent device coordination

• Overcurrent device ratings >100 100 to 20

Less than

20

Ground Source

Impedance

Ratio(2)

• Ground fault desensitization

• Overcurrent device coordination

and ratings>100 100 to 20

Less than

20

StiffnessFactor

(ISCUtililty/IRatedDG)

• Voltage Regulation

(this ratio is a good indicator of voltageinfluence. Wind/PV have higher ratios

due to their fluctuations. Besides this

ratio, may need to check for current

reversal at upstream regulator devices.)

>100PV/Wind

100 to 50PV/Wind

Less than 50PV/Wind

> 50Steady Source

50 to 25Steady Source

Less than 25Steady Source

Notes:1. Ratios are meant as guides for radial 4-wire multigrounded neutral distribution system DG applications and are calculated based on aggregate DG on relevant power system sections

2. Useful when DG or it’s interface transformer provides a ground source contribution. Must include effect of grounding step -up transformer and/or accessory ground banks if present.

3. If DG application falls in this “higher penetration” category it means some system upgrades/adjustments are likely needed to avoid power system issues.


Screening Ratios (Continued)



8/41NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

What Does it Mean if it Falls

Into the Higher Penetration Category?

• If the DG application falls into these higher penetration

categories , then a detailed study is generally recommended

and may lead to the need for mitigation



9/41

In addition to the ratios discussed in the prior

slides, also check for:

• Reverse power flow at any voltage regulator or transformer LTC bank: if

present, check compatibility of the controls and settings of regulator

controls.

• Check line drop compensation interaction: if employed by any upstream

regulator, do a screening calculation of the voltage change seen at theregulator with the R and X impedance settings actually employed at the

regulator. Generally, if ΔV < 1% seen by the regulator controller

calculated for the full rated power change of DG, then line drop

compensation effects and LTC cycling is not usually an issue.

• Capacitor Banks: if significant VAR surplus on a possible islanded area

study for potential impact

• Fast Reclosing Dead Times: if less than 5 seconds (especially those less

than 2 seconds) consider the danger of reclosing into live island.



10/41

Caveats for Use of the Ratios & Checks

• Ratios we have discussed on preceding slides are only guides

for establishing when distribution and subtransmission system

effects of DG become “significant” to the point of requiring

more detailed studies and/or potential mitigation options.

• They must be applied by knowledgeable engineers that

understand the context of the situation and the exceptions

where the ratios don’t work

• It requires a lot more than just these slides here to do this topic

justice. We have omitted a lot of details due to the short

presentation format so this is just meant as a brief illustration

of these issues.

NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLCPrepared by Nova Energy Specialists, LLC 10


11/41

Voltage Regulation & Variation Issues

• Steady State Voltage (ANSI C84.1 voltage

limits)

• Voltage Excursions and LTC Cycling

• Voltage Flicker

• Line Drop Compensator Interactions

• Reverse Power Interactions

• Regulation Mode Compatibility Interactions



12/41

High Voltage Caused by Too Much

DG at End of Regulation Zone

SUBSTATION

Voltage

Distance

Heavy Load No DG

Heavy Load

(DG High Output)

End

ANSI C84.1 Lower

Limit (114 volts)

Light Load

(DG at High Output)ANSI C84.1 UpperLimit (126 volts)

Cos RSin X I V DG

LTC Large DG exports

large amounts of

power up feeder

I DG

Feeder (with R and X)

IEEE 1547 trip Limit (132 Volts)


DG current

at angle


13/41

Impact of Distributed Generation

on Line Drop Compensation

V o l t a

g e

Distance

Heavy Load No DG

Heavy Load with DG

End

ANSI C84.1 Lower Limit (114 volts)

Light Load No DG

SUBSTATIONLTC

Large DG(many MW)

DG Supports most of

feeder load

Exporting DG “shields” the

substation LTC controller

from seeing the feeder

current. The LTC sees less

current than there is and

does not boost voltage

adequately.

CT

Line drop

compensator

LTC Controller


ANSI C84.1 Upper Limit (114 volts)


14/41

Voltage Regulator Reverse Mode

Confused by DG Reverse Power

SUBSTATION

LTC

Reverse

Power Flow

Due to DG

Supplementary

Regulator with Bi-

Directional controls

Normally

Closed

Recloser

R

R

Normally

Open

Recloser

DG

Supplementary regulator senses reverse power and

erroneously assumes that auto-loop has operated – it

attempts to regulate voltage on the substation side of

the supplementary regulator

What happens? Since the feeder is still connected to the substation, the line regulator once it isforced into the reverse mode will be attempting to regulate the front section of the feeder. To do

this can cause the supplementary regulator to “runaway” to either its maximum or minimum tap

setting to attempt to achieve the desired set voltage. This in turn could cause dangerously high or

low voltage on the DG side of the regulator. This occurs because the source on DG side of regulator

is voltage following (not aiming to a particular voltage set point) and is weak compared to the

substation source.



15/41

Fluctuating Output of aPhotovoltaic Power Plant


1 2 3 4 5 6 7 8 9

Days


16/41

Cos RSin X I V DG

System Impedance

DG Starting Current

and DG Running current

fluctuations DG

ΔIDG

Infinite

Source R X

V Flicker Voltage Example

The GE Flicker Curve

(IEEE Standard 141-1993 and 519-1992)Flicker

Screening:Using the voltage drop screeningformula to estimate the ΔV for a

given DG current change (ΔIDG).

Then plot ΔV on the flicker curve

using expected time period

between fluctuations

Realize that this is a basic screening concept. For situationswhere there might be more significant dynamic interactionswith other loads, or utility system equipment, a dynamicsimulation with a program such as EMTP or PSS/E may berequired to verify if flicker will be visible.



17/41

A Conservative Quick Screen for PV Flicker(Not as accurate as IEEE 1453 method but easy and quick for PV)


P e r c e n t V o l t a g e C h a n g e ( V % )

Adjusted Borderline of Visibility Curves for PV: This

curve used/developed by NES represents a conservativemodification to the regular IEEE flicker visibility curve. This

curve for PV is meant to capture the fact that PV is not

square modulation, and is based on cloud ramping rates,

and possible LTC interactions causing flicker.

IEEE 519-1992 Borderline of Irritation Curve

519 Visibility

Curve x 2.0

519 Irritation

Curve x

1.25X

Adjusted Borderline of Irritation Curve for PV: This curve used/developed by

NES represents a conservative modification to the regular IEEE flicker irritation

curve. This curve for PV is meant to capture the fact that PV is not squaremodulation, and is based on cloud ramping rates, and possible LTC interactions

causing flicker.

IEEE 519-1992 Borderline

of Visibility Curve

This is the IEEE 519-1992 flicker

curve, but with two new adjusted

curves added by NES to

conservatively approximate PV

flicker thresholds.

While the IEEE 1453 method basedon Pst, Plt is still the most

technically robust approach and

should allow best results in tight

situations, it is the author’s view that

this adjusted IEEE 519-1992 curve

approach shown here can serve as

a cruder but easier alternative

method to facilitate quick screens.

Note that for PV, the regular IEEE

519-1992 curves are generally too

conservative from a flicker visibility

perspective due to the fact that PV

fluctuations are more rounded rather

than square.


18/41

PV Flicker Experiences

• Use of IEEE 1453 method is a technically very robust

screening methodology for flicker when very accurate

threshold levels need to be determined

• However, a suggested modified GE flicker curve canwork well for PV as a conservative tool for simple

screening when less accuracy is required

• It is the author’s experience that other voltageproblems (LTC cycling, ANSI limits, etc.) related to PV

become problematic at lower capacity thresholds

than flicker – flicker is one of the last concerns to arise



19/41

Some DG Fault Current Issues

• Impact of current on breaker, fuse, recloser,

coordination. Affect on directional devices and

impedance sensing devices.

• Increase in fault levels (interrupting capacity of

breakers on the utility system)

• Nuisance trips due to “backfeed” fault current

• Distribution transformer rupture issues

• Impact on temporary fault clearing/deionization



20/41

Fault Currents of Rotating Machines

Separately-ExcitedSynchronous Generator

2 to 4 times rated current

F a u l t C u r r e n

t

Time

Subtransient Period

Envelope

Transient Period

Envelope Steady State Period

Envelope

F a u l t C u r r e n

t

Time

Subtransient Period

Envelope

Transient Period

Envelope Steady State Period

Envelope

4-10 times rated current

Induction Machine

Current decays toessentially zero

Current Decay Envelope

37%

Transient Time Constant

Time

100%

F a u l t C u r r e n t

4-10 timesrated current



21/41

Pre-fault Fault Current Worst casei

t

Fault Current Contributions of Inverters

Note: The exact nature and duration of the fault contribution from aninverter is much more difficult to predict than a rotating machine. It is afunction of the inverter controller design, the thermal protection functionsfor the IGBT and the depth of voltage sag at the inverter terminals. Inthe worst case if fault contributions do continue for more than ½ cycle,they are typically no more than 1 to 2 times the inverter steady statecurrent rating.

Best Case: May last only a fewmilliseconds (less than ½ cycle) for manytypical PV, MT and fuel cell inverters

Typical Worst Case: may last forup to the IEEE 1547 limits and be upto 200% of rated current

Irated



22/41

Fault Current Impacts:Nuisance trips, fuse

coordination issues,transformer rupture issues, etc.

Recloser B

13.2 kV

115 kV

Recloser A

DG

Adjacent

Feeder

FaultCase 1

Fault Contribution

from DG Might

Trip The Feeder

Breaker and

Recloser

(Nuisance trip)

Iutility

IDG


Fault

Case 2

U t i l i t y

DG

U t i l i t y

D G

Fault

Case 3

The good news is that PV is

much less likely than

conventional rotating DG to

cause issues since inverter faultcontributions are smaller!Fault Contribution from

DG Might Interfere with

Fuse Saving or Exceed

Limits of a DeviceTransformer Rupture

Limits (fault magnitude)


23/41

The Author’s Experiences

Related to PV Fault Levels

• In doing many projects, I have observed that fault current

problems associated with PV in most cases are not an issue

due to the low currents injected by the inverter (about 1-2

per unit of rating).

• In general, only the largest PV (or large PV aggregations) can

cause enough fault current to even begin to worry current

impacts (there are some special exceptions).

• As PV capacity grows on a circuit, voltage problems usually

arise well before fault currents become an issue. A circuit

without voltage problems is not likely to have fault current

problems due to PV.



24/41

Unintentional DG

Islanding Issues

Recloser B

(Normally Open)

13.2 kV

115 kV

Recloser A

DG

Adjacent

Feeder

The recloser has

tripped on its first

instantaneous shot,

now the DG must trip

before a fast reclose is

attempted by the utility

Islanded Area

• Incidents of energizeddowned conductorscan increase (safety)

• Utility system reclosinginto live island may

damage switchgearand loads

• Service restoration canbe delayed and willbecome moredangerous for crews

• Islands may notmaintain suitablepower quality

• Damaging overvoltagescan occur during some

conditionsPrepared by Nova Energy Specialists, LLC 24


25/41

Islanding Protection Methods of DG

Passive Relaying Approach (Voltage and frequencywindowing relay functions: 81o, 81u, 27, 59 – ifconditions leave window then unit trips)

Active Approach (instability induced voltage orfrequency drift coupled and/or actively perturbedsystem impedance measurement or other activeparameter measurement)

(UL-1741 utility interactive inverters)

Communication Link Based Approach (use of directtransfer trip [DTT] or other communications means)



26/41

Islanding and PV Inverters

• Inverters typically have very effective active anti-

islanding protection.

• Unfortunately, the IEEE 1547 and UL-1741 islanding

protection requirements (2 second response time)are not compatible with high speed utility reclosing

practices used at many utilities

• If minimum load is nearly matched to generationthen provisions such as DTT and/or live line reclose

blocking may be needed, especially with high

speed reclosing situations.



27/41

Screening

for

Islanding

Issues


Start

Is the annual minimum load on any

“Islandable” section at least twice the rated DG

capacity?

Is the DG an Inverter Based

Technology Certified Per

UL1741 Non-IslandingTest?

Islanding Protection May Need

Careful Examination and

Possible Enhancement

Islanding Protection is

Adequate

Yes

No

Yes

Yes

No

No Is the reclosing dead time on the “Islandable”

section ≥ 5 seconds?

Is the DG equipped with at least passive relaying-

based islanding protection?

No

Is the mix of (number of and

capacity) inverters and other

converters and capacitors on the

“Islandable” section within

comfortable limits of the UL1741

algorithms?

No

Yes

Yes


28/41

Ground Fault Overvoltage


can result in seriousdamaging overvoltage on theunfaulted phases. It can beup to roughly 1.73 per unit ofthe pre-fault voltage level.

Neutral

Vcn

Van

Vbn

Before the Fault

Neutral

Voltage

Increases

on Van, Vbn

Vbn

Van

Vcn

During the Fault

Neutral and earth return path

Phase A

Phase B

Phase C

Source

Transformer

(output side)

Fault V bn

V an

V cn

X1, X2 R1, R2

X0 R0

Voltage swell during

ground fault

V(t)

(t)


X1, X2

X1, X2 R1, R2

R1, R2


29/41

IEEE Effective Grounding

• Effective grounding is

achieved when the source

impedance has the following

ratios:

Ro/X1 < 1Xo/X1 < 3

• Effective grounding limits the

L-G voltage on the unfaulted

phases to roughly about

1.25-1.35 per unit of nominal

during the fault

• With ungrounded source, the

voltage could be as high as

1.82 per unit.

ideally

grounded

system

Vbn

Van

Vcn

Effectively

grounded

system

Ungrounded

system

N

N

N

1.82 VLN


Voltage

includes 5%

regulation

factor


30/41

Generator Step-Up Transformer

Grounding Issues

deltaNeutral

Neutral

Low Voltage Side (DG facility)

wye

wye wye

Neutral grounding of

generator on low side of

transformer does not impact

grounding condition on high

side

*IMPORTANT: Generator

neutral must be

connected to the

neutral/ground of the

transformer to establish

zero sequence path to

high side

Neutral wye*neutral is not connected

then the source acts as

an ungrounded source

even though transformer

is grounded-wye to

grounded-wye

Acts as grounded

source feeding out to

system only if

generator neutral istied to the transformer

grounded neutral

Acts as ungrounded

source feeding out to

system only if generator

neutral is not connectedto transformer grounded

neutral*

Acts as grounded

source feeding out

to system

C N

A

B

Gen.

C

C N

A

B

Gen.

C

C N

A

B

Gen.

C

Distribution

Transformer

wye

High Voltage Side(to Utility Distribution System Primary)


G t St U T f


31/41

Generator Step-Up Transformer

Grounding Issues – Continued

deltaNeutral

Low Voltage Side (DG facility)

wye





side

Acts as ungrounded

source feeding out

to system

C N

A

B

Gen.

C

Distribution

Transformer

High Voltage Side(to Utility Distribution System Primary)

delta

Acts as

ungrounded

source feeding out

to system





side

C N

A

B

Gen.

Cdelta

delta wye Neutral grounding at generator

on low side of transformer does

not impact grounding condition

on high side

Acts as

ungrounded

source feeding out

to system

C N

A

B

Gen.

C

Floating Neutral

No connection toTransformer Neutral


PV Inverter Neutral Is Typically Not


32/41

PV Inverter – Neutral Is Typically Not

Effectively Grounded


Building Neutral

A

A

B

C

Utility

Distribution

Transformer 480V

277V

Delta

12,470V

Wye

B

C

Wye has high resistance neutral

grounding or is essentially ungrounded

Three Phase Inverter with Internal Isolation Transformer all inside an enclosure – a typical arrangement

Safety Ground

Enclosure bond

to safety

ground

Neutral

Neutral Terminal

Usually bonded to earth ground at main service panel

per NEC but this does not make it effectively

grounded if inverter transformer is not so


33/41

Ground Fault Overvoltage Issues


Need enough load on this island with respect aggregate

DG at all connected distribution substations to suppress

overvoltage –

otherwise special solutions are needed!

12.47 kV Line

DG Site 1

Ground

Fault

Feeder

Breaker

Utility System

Bulk Source

Load Load Load

Need enough load on this island with respect aggregate DG

at distribution level to suppress overvoltage – otherwise

effective grounding or other solutions are needed!

Transformer Acts as

ungrounded source

(not effectively

grounded)

Substation transformer acts as grounded source with respect to 12.47

feeder suppressing ground fault overvoltage on distribution until feeder

breaker opens. But it acts as an ungrounded source when feeding

backwards into subtransmission!

Neutral is Ungrounded

or High Z Grounded

Transformer acts as

ungrounded source or acts as

high Z grounded source (if

generator neutral is not

grounded or high z grounded)DG Site 2

Subtransmission

(46kV)

Subtransmission source transformer acts as grounded source

suppressing ground fault overvoltage on subtransmission until

subtransmission breaker opens.

Ground

Fault

Distribution

SubstationDG

DG

Distribution

Substation

Load

Load

Distribution

Substation

Subtransmission

Breaker


34/41

Solutions to Ground Fault Overvoltage(any one of these alone will work)

• Effectively ground the DG if possible(But be careful since too much effectively grounded DG can desensitize relaying and cause

other issues. Also, see note 1 with regard to subtransmission impacts of distribution effective

grounding of DG.)

• If DG is not effectively grounded make sure to maintain a minimum loadto aggregate generation ratio >5 for rotating DG and >3 for inverter

generation

• Don’t separate the feeder from the substation grounding source

transformer until sufficient non-effectively grounded DG is “cleared” from

the feeder (e.g. use a time coordinated DTT method.)

• Use grounding transformer banks at strategic point(s) on feeder.


Note 1: On subtransmission since the distribution substations usually feed in through delta (high-side)

windings, effective grounding of DG at the distribution level does not make it effectively grounded with

respect to subtransmission level.

H L d R d


35/41

How Load Reduces


Neutral

Vcg

Vag

Vbg

Before the

Fault

12.47 kV Feeder

Load

Impedance of DG

Source, its transformerand connecting leads

Ground Fault

(phase C)Open

BreakerUtility Source

Neutral

Voltage

Increases

on Vag, Vbg

VbgVcg=0

During Ground Fault

(light load)

Neutral

Voltage does not rise much on Vag, Vbg because the overall size of the

triangle has been reduced (phase to phase voltage has dropped)

Vbg

During Ground Fault

(heavy load)

X

R

Vag

Vcg=0

Vag


For inverters theexcessive load will

also trigger fast

shutdown to protect

transistors


36/41

Grounding Transformer Impedance Sizing


1

3

1

0

1

0

pv

groundbank

pv

groundbank

X

R

X

X

IEEE Effective Grounding Definition

7.0

2

1

0

1

0

pv

groundbank

pv

groundbank

X

R

X

X

Engineering Targets to Provide Effective

Grounding with Reasonable MarginAssume inverter X1 is 30% for generic worst case30% is not the actual impedance since the inverter

impedance varies due to controller dynamics and operating

state. But 30% is a conservative number that factors worst

case conditions whether the inverter is a current controlled

or voltage controlled PV source. A higher number can be

used for some inverters, but care should be exercised if using

a higher value (especially if it exceeds 50%).

Utility

Primary

Feeder

X1PV = 30% X

t=5%

Utility Source

Grounding

Transformer

Bank

X0groundbank, R0groundbank

Open

Inverter


37/41

Ground Transformer Sizing/Rating

• Must be sized such that:

– X0/X1 and R0/X1 ratios are

satisfied with some margin (see

the targets prior slide)

– Bank must be able to handle fault

currents and steady state zero

sequence currents without

exceeding damage limits

– Bank must not desensitize the

utility ground fault relaying or

impact ground flow currents too

much

– Bank may need alarming or

interlock trip of DG if bank trips off.


Zero Sequence Current Divider

GroundingTransformer

Path

UtilitySource

Path

I0 utility

I0 Total

I0 Ground transformer

d L d


38/41

Ferroresonance and Load

Rejection Overvoltage with DG

Conditions to Avoid: Islanded State (Feeder Breaker open)

Generator Rating > minimum load on island

Excessive Capacitance on island

Reliable and fast anti-islanding protection that

clears DG from line before island forms is a

good defense against this type of ferroresonant

condition! Reasonably high MLGR avoids it too.

EMTP Simulation of Ferroresonant

OvervoltageUnfaulted Phase Voltage

Load rejection, ground fault and

resonance related overvoltage

Breaker Opens (island forms)

Normal Voltage


Waveform shown is Rotating

Machine Type Overvoltage


39/41

Outcomes of PV Projects (0.1 to 5 MW) the Author Has

Been Involved With in Various Locations


Type of Issue Typical Experience (over 30 projects studied)

Voltage

Regulation

Interactions

Most have not required changes to the regulator or regulation settings and no

special mitigation. A few projects have required regulator setting changes to

reduce the chance of LTC cycling or ANSI C84.1 voltage violations. The largest

sites studied are considering reactive compensation to mitigate LTC cycling and

voltage variations.

Fault CurrentInteractions

No sites except one caused enough additional fault current to impactcoordination or device ratings in a significant manner.

Islanding

Interactions

For islanding protection, roughly 1/3rd of the sites have required something

special beyond the standard UL-1741 inverter with default settings. Some

required more sensitive inverter settings or adjustments to utility reclosing

dead time. A few have needed a radio based or hardwired DTT and/or live line

reclose blocking added.

Ground Fault

Overvoltage

About 1/3rd of the sites need some form of mitigation – usually a grounding

transformer bank, a grounded inverter interface, or a time coordinated DTT

Harmonics No sites have required any special provisions for harmonics yet

OtherSome sites are considering operating in power factor mode producing VARs to

provide reactive power support. One site had a capacitor concern.


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Conclusions

• PV and other types of DG today are being successfully

interconnected on distribution feeders all over the country.

In many cases the impacts are not enough to cause

worrisome effects.

• However, the size of projects is growing, especially now that

many large commercial and FIT type projects are being

considered at the distribution level. Also, the ongoing

aggregation effects as PV becomes more widely adopted is

leading to more substantial impacts.

• Many projects can still be screened using simple methods,

but increasingly, more detailed analytical methods are

becoming necessary.Prepared by Nova Energy Specialists, LLC 40


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Conclusions (continued)

• The “relative size” of the PV (or DG) compared to the power

system to which it is connected plays the key role in system

impact effects. Key factors that gauge the relative size include:

– The MLGR, FRF (SCCR), Stiffness Factor, and GSIR

– The ratios will usually need to be gauged based on aggregate DG in a

zone or region of concern

• The settings of utility voltage regulation equipment and feeder

overcurrent devices and system designs also play a key role.

• The “absolute size” and “project class” (e.g. FIT, net metered)

play a role only in that this impacts the scope and criticality of

the project and may trigger certain regulatory requirements.

PVDGIntegration Barker

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