experiences in integrating pv and other dg to the power …€¢ minimum load to generation ratio...

Experiences in Integrating PV and Other DG to the Power System

(Radial Distribution Systems)

Prepared by:

Philip Barker

Founder and Principal Engineer Nova 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, CO

1 Prepared by Nova Energy Specialists, LLC

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


12.47 kV

Subtransmission Line

Substation

Transformer

LTC

DG

Distribution

Feeder

Rotating Machine or

Inverter 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 and

LTC Settings

Capacitor

Alt. Feed

Alt. Feed

Other load and

DG scattered on

feeder

Type of

Grounding

Prime mover or

energy source

characteristics

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 DG

rated 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 zero

sequence 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


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

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)

>10 Synchronous Gen.

10 to 5 Synchronous Gen.

Less than 5 Synchronous Gen.

>6 Inverters(3)

6 to 3 Inverters(3)

Less than 3 Inverters(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 machines

4. 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


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 Ratio Factor

(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

Stiffness Factor

(ISCUtililty/IRatedDG)

• Voltage Regulation (this ratio is a good indicator of voltage influence. Wind/PV have higher ratios due to their fluctuations. Besides this ratio, may need to check for current reversal at upstream regulator devices.)

>100 PV/Wind

100 to 50 PV/Wind

Less than 50 PV/Wind

> 50 Steady Source

50 to 25 Steady Source

Less than 25 Steady 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)



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


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 the regulator 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.


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.



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


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 Upper

Limit (126 volts)

CosRSinXIVDG

LTC Large DG exports large amounts of power up feeder

IDG

Feeder (with R and X)

IEEE 1547 trip Limit (132 Volts)


DG current

at angle

Impact of Distributed Generation on Line Drop Compensation

Vo

ltag

e

Distance

Heavy Load No DG

Heavy Load with DG

End

ANSI C84.1 Lower Limit (114 volts)

Light Load No DG

SUBSTATION LTC

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)

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 is forced 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.


Fluctuating Output of a Photovoltaic Power Plant


1 2 3 4 5 6 7 8 9

Days

CosRSinXIVDG

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 screening formula 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 situations where there might be more significant dynamic interactions with other loads, or utility system equipment, a dynamic simulation with a program such as EMTP or PSS/E may be required to verify if flicker will be visible.


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


Pe

rce

nt V

olta

ge

Ch

an

ge

(

V%

)

Adjusted Borderline of Visibility Curves for PV: This

curve used/developed by NES represents a conservative

modification 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 square

modulation, 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 based

on 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.

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 can work well for PV as a conservative tool for simple screening when less accuracy is required

• It is the author’s experience that other voltage problems (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


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


Fault Currents of Rotating Machines

Separately-Excited Synchronous Generator

2 to 4 times rated current

Faul

t Cur

rent

Time

Subtransient Period

Envelope

Transient Period

Envelope Steady State Period

Envelope

Faul

t Cur

rent

Time

Subtransient Period

Envelope

Transient Period

Envelope Steady State Period

Envelope

4-10 times rated current

Induction Machine

Current decays to essentially zero

Current Decay Envelope

37%

Transient Time Constant

Time

100%

Fau

lt C

urr

ent

4-10 times rated current


Pre-fault Fault Current Worst case i

t

Fault Current Contributions of Inverters

Note: The exact nature and duration of the fault contribution from an inverter is much more difficult to predict than a rotating machine. It is a function of the inverter controller design, the thermal protection functions for the IGBT and the depth of voltage sag at the inverter terminals. In the 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 state current rating.

Best Case: May last only a few milliseconds (less than ½ cycle) for many typical PV, MT and fuel cell inverters

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

Irated


Fault Current Impacts: Nuisance trips, fuse coordination issues, transformer rupture issues, etc.

Recloser B

13.2 kV

115 kV

Recloser A

DG

Adjacent Feeder

Fault Case 1

Fault Contribution from DG Might Trip The Feeder

Breaker and Recloser

(Nuisance trip)

Iutility

IDG


Fault Case 2

Utilit

y

DG U

tilit

y

DG

Fault Case 3

The good news is that PV is

much less likely than

conventional rotating DG to

cause issues since inverter fault

contributions are smaller! Fault Contribution from DG Might Interfere with Fuse Saving or Exceed

Limits of a Device Transformer Rupture Limits (fault magnitude)

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.


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 energized downed conductors can increase (safety)

• Utility system reclosing into live island may damage switchgear and loads

• Service restoration can be delayed and will become more dangerous for crews

• Islands may not maintain suitable power quality

• Damaging overvoltages can occur during some conditions


Islanding Protection Methods of DG

Passive Relaying Approach (Voltage and frequency windowing relay functions: 81o, 81u, 27, 59 – if conditions leave window then unit trips)

Active Approach (instability induced voltage or frequency drift coupled and/or actively perturbed system impedance measurement or other active parameter measurement) (UL-1741 utility interactive inverters)

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


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 generation then provisions such as DTT and/or live line reclose blocking may be needed, especially with high speed reclosing situations.


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

Ground Fault Overvoltage

Ground Fault Overvoltage can result in serious damaging overvoltage on the unfaulted phases. It can be up to roughly 1.73 per unit of the 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 Vbn

Van

Vcn

X1, X2 R1, R2

X0 R0

Voltage swell during ground fault

V(t)

(t)


X1, X2

X1, X2 R1, R2

R1, R2

IEEE Effective Grounding

• Effective grounding is achieved when the source impedance has the following ratios:

Ro/X1 < 1

Xo/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

Generator Step-Up Transformer Grounding Issues

delta Neutral

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 is

tied to the transformer

grounded neutral

Acts as ungrounded

source feeding out to

system only if generator

neutral is not connected

to 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)


Generator Step-Up Transformer Grounding Issues – Continued

delta Neutral

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.

C delta

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 to

Transformer Neutral


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

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

DGDistribution Substation

Load

Load

Distribution Substation

Subtransmission Breaker

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 load to 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.

How Load Reduces Ground Fault Overvoltage

Neutral

Vcg

Vag

Vbg

Before the Fault

12.47 kV Feeder

Load

Impedance of DG

Source, its transformer

and connecting leads

Ground Fault (phase C)

Open Breaker Utility Source

Neutral

Voltage Increases on Vag, Vbg

Vbg Vcg=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 the

excessive load will

also trigger fast

shutdown to protect

transistors

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 Margin Assume inverter X1 is 30% for generic worst case 30% 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%

Xt=5%

Utility Source

Grounding

Transformer

Bank

X0groundbank, R0groundbank

Open

Inverter

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

Grounding Transformer Path

Utility Source Path

I0 utility

I0 Total

I0 Ground transformer

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 Overvoltage

Unfaulted Phase Voltage

Load rejection, ground fault and

resonance related overvoltage

Breaker Opens (island forms)

Normal Voltage


Waveform shown is Rotating

Machine Type Overvoltage

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 Current Interactions

No sites except one caused enough additional fault current to impact coordination 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

Other Some sites are considering operating in power factor mode producing VARs to provide reactive power support. One site had a capacitor concern.

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.


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.


experiences in integrating pv and other dg to the power …€¢ minimum load to generation ratio...

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