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: pbarker@nycap.rr.com
Presented at:
Utility Wind Interest Group (UWIG)
6th Annual Distributed Wind/Solar Interconnection Workshop
February 22-24, 2012
Golden, CO
Prepared by Nova Energy Specialists, LLC
1
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
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2
Discussion of
Some Factors to
Consider in DG
Integration
Alt. Feed
Other Substations
with Load and DG
Subtransmission Line
Substation
Transformer
LTC
12.47 kV
Regulator and
LTC Settings
Subtransmission
Source
Adjacent
Feeders
Reclosing and
Relay Settings
Distribution
Feeder
Type of
Grounding
Voltage Regulator
Other load and
DG scattered on
feeder
Step Up
Transformer
DG
Primary Feeder
Point of Connection
(POC)
Alt. Feed
Rotating Machine or
Inverter based DG
Customer
Site Load
Capacitor
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Bulk
System
Prime mover or
energy source
characteristics
3
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)
Note: all ratios above are based on the aggregate DG sources on the system area of interest where appropriate
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NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them
Phil Barker, Nova Energy Specialists, LLC
4
Minimum Load to Generation Ratio
(MLGR)
Weekdays
Peak Load
Minimum Weekend
Load
Annual Minimum Load
False Minimum
Time (up to 1 year is ideal)
• Try to use the annual minimum load (don’t
just assume 1 week of measurements gives
the minimum)
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5
Some Helpful Screening Thresholds
the Author Uses in His Studies
Suggested Penetration Level Ratios(1)
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.)
• MLGR used for Ground Fault
Overvoltage Suppression Analysis
Minimum
Load to
Generation
Ratio
[MLGR](2)
(use ratios shown when DG is not effectively
grounded)
Very Low
Penetration
Moderate
Penetration
Higher
Penetration(4)
(Very low probability
of any issues)
(Low to minor probability
of issues)
(Increased probability
of serious issues.
>10
10 to 5
Less than 5
Synchronous Gen.
Synchronous Gen.
Synchronous Gen.
>6
6 to 3
Less than 3
Inverters(3)
Inverters(3)
Inverters(3)
>4
4 to 2
Less than 2
• 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.)
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.
Prepared by Nova Energy Specialists, LLC
NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them
Phil Barker, Nova Energy Specialists, LLC
6
Screening Ratios
Type of
Ratio
Fault Ratio
Factor
(ISCUtility/ISCDG)
Ground Source
Impedance
Ratio(2)
Stiffness
Factor
(ISCUtililty/IRatedDG)
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.)
• Overcurrent device coordination
• Overcurrent device ratings
• Ground fault desensitization
• Overcurrent device coordination
and ratings
• 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.)
(Continued)
Suggested Penetration Level Ratios(1)
Very Low
Penetration
Moderate
Penetration
Higher
Penetration(3)
(Very low probability
of any issues)
(Low to minor probability
of issues)
(Increased probability
of serious issues.
>100
100 to 20
Less than
20
>100
100 to 20
Less than
20
>100
100 to 50
Less than 50
PV/Wind
PV/Wind
PV/Wind
> 50
50 to 25
Less than 25
Steady Source
Steady Source
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.
Prepared by Nova Energy Specialists, LLC
NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them
Phil Barker, Nova Energy Specialists, LLC
7
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
Prepared by Nova Energy Specialists, LLC
NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them
Phil Barker, Nova Energy Specialists, LLC
8
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.
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9
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.
Prepared by Nova Energy Specialists, LLC
NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them
Phil Barker, Nova Energy Specialists, LLC
10
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
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11
High Voltage Caused by Too Much
DG at End of Regulation Zone
LTC
SUBSTATION
Feeder (with R and X)
Large DG exports
large amounts of
power up feeder
DG current
at angle 
IDG
V  I DG  X Sin   R Cos  
IEEE 1547 trip Limit (132 Volts)
ANSI C84.1 Upper
Limit (126 volts)
Light Load
(DG at High Output)
Voltage
Heavy Load
(DG High Output)
ANSI C84.1 Lower
Limit (114 volts)
Heavy Load No DG
Distance
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End
12
Impact of Distributed Generation
on Line Drop Compensation
SUBSTATION
LTC
CT
DG Supports most of
feeder load
Line drop
compensator
LTC Controller
Large DG
(many MW)
ANSI C84.1 Upper Limit (114 volts)
Heavy Load No DG
Voltage
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.
Heavy Load with DG
Light Load No DG
ANSI C84.1 Lower Limit (114 volts)
Distance
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End
13
Voltage Regulator Reverse Mode
Confused by DG Reverse Power
SUBSTATION
LTC
Normally
Closed
Recloser
Supplementary
Regulator with BiDirectional controls
Normally
Open R
Recloser
R
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
Reverse
Power Flow
Due to DG
DG
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.
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14
Fluctuating Output of a
Photovoltaic Power Plant
1
2
3
4
5
6
7
8
9
Days
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15
Flicker
Screening:
The GE Flicker Curve
(IEEE Standard 141-1993 and 519-1992)
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
System Impedance
Infinite
Source
R
ΔIDG
X
DG Starting Current
and DG Running current
fluctuations
V
Flicker Voltage Example
DG
V  I DG  X Sin   R Cos  
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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.
16
A Conservative Quick Screen for PV Flicker
(Not as accurate as IEEE 1453 method but easy and quick for PV)
This is the IEEE 519-1992 flicker
curve, but with two new adjusted
curves added by NES to
conservatively approximate PV
flicker thresholds.
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.
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IEEE 519-1992 Borderline of Irritation Curve
Percent Voltage Change (V%)
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.
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.
519 Irritation
Curve x
1.25X
519 Visibility
Curve x 2.0
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 Visibility Curve
17
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
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18
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
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19
Fault Currents of Rotating Machines
4-10 times rated current
Separately-Excited
Synchronous Generator
Subtransient Period
Envelope
Fault Current
Transient Period
Envelope
Steady State Period
Envelope
Time
4-10 times
rated current
2 to 4 times rated current
Induction Machine
Transient Time Constant
Fault Current
100%
Current Decay Envelope
37%
Time
Current decays to
essentially zero
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20
Fault Current Contributions of Inverters
i
Pre-fault
Fault Current Worst case
t
Irated
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
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.
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21
115 kV
Fault Current Impacts:
Fault Contribution
from DG Might
Trip The Feeder
Breaker and
Recloser
(Nuisance trip)
13.2 kV
Nuisance trips, fuse
coordination issues,
transformer rupture issues, etc.
Transformer Rupture
Limits (fault magnitude)
Recloser A
Fault
Case 2
Utility
The good news is that PV is
much less likely than
conventional rotating DG to
cause issues since inverter fault
contributions are smaller!
IDG
DG
DG
Fault Contribution from
DG Might Interfere with
Fuse Saving or Exceed
Limits of a Device
DG
Fault
Case 1
Utility
Adjacent
Feeder
Iutility
Fault
Case 3
Recloser B
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22
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.
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23
Unintentional DG
Islanding Issues
• 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
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115 kV
13.2 kV
The recloser has
tripped on its first
instantaneous shot,
now the DG must trip
before a fast reclose is
attempted by the utility
Adjacent
Feeder
Recloser A
Islanded Area
DG
Recloser B
(Normally Open)
24
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)
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25
Islanding and PV Inverters
• Inverters typically have very effective active antiislanding 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.
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26
Start
Screening
for
Islanding
Issues
No
Is the DG equipped with at least passive relayingbased islanding protection?
Yes
No
Is the reclosing dead time on the “Islandable”
section ≥ 5 seconds?
Yes
No
Is the annual minimum load on any
“Islandable” section at least twice the rated DG
capacity?
Yes
No
Is the DG an Inverter Based
Technology Certified Per
UL1741 Non-IslandingTest?
Yes
No
Islanding Protection May Need
Careful Examination and
Possible Enhancement
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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?
Yes
Islanding Protection is
Adequate
27
Ground Fault Overvoltage
Voltage swell during
ground fault
X 1, X 2
R1, R2
X 1, X 2
R1, R2
X 1, X 2
R1, R2
Phase A
V(t)
Phase B
Source
Transformer
(output side)
Phase C
(t)
Van
Vbn
Fault
Vcn
R0
X0
Neutral and earth return path
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.
Before the Fault
Van
Van
Voltage
Increases
on Van, Vbn
Neutral
Neutral
Vcn
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During the Fault
Vbn
Vcn
Vbn
28
IEEE Effective Grounding
• Effective grounding is
achieved when the source
impedance has the following
ratios:
Van
Voltage
includes 5%
regulation
factor
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.
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Effectively
grounded
system
ideally
grounded
system
N
N
Vcn
N
Ungrounded
system
1.82 VLN
Vbn
29
Generator Step-Up Transformer
Grounding Issues
Distribution
Transformer
High Voltage Side
(to Utility Distribution System Primary)
Acts as grounded
source feeding out
to system
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*
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Neutral
wye
Low Voltage Side
(DG facility)
Gen.
delta
A
N
C
C
Neutral grounding of
generator on low side of
transformer does not impact
grounding condition on high
side
B
Gen.
Neutral
wye
wye
A
*IMPORTANT: Generator
neutral must be
connected to the
neutral/ground of the
transformer to establish
zero sequence path to
high side
N
C
C
B
Gen.
Neutral
wye
wye
A
N
C
C
B
*neutral is not connected
then the source acts as
an ungrounded source
even though transformer
is grounded-wye to
grounded-wye
30
Generator Step-Up Transformer
Grounding Issues – Continued
High Voltage Side
Distribution
Transformer
(to Utility Distribution System Primary)
Acts as
ungrounded
source feeding out
to system
Low Voltage Side
(DG facility)
Gen.
delta
delta
A
N
C
C
B
Neutral grounding of
generator on low side of
transformer does not impact
grounding condition on high
side
No connection to
Transformer Neutral
Acts as ungrounded
source feeding out
to system
Neutral
wye
Gen.
delta
A
N
C
C
Neutral grounding of
generator on low side of
transformer does not impact
grounding condition on high
side
B
Floating Neutral
Acts as
ungrounded
source feeding out
to system
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Gen.
delta
wye
A
N
C
C
B
Neutral grounding at generator
on low side of transformer does
not impact grounding condition
on high side
31
PV Inverter – Neutral Is Typically Not
Effectively Grounded
Three Phase Inverter with Internal Isolation Transformer all inside an enclosure – a typical arrangement
C
Wye
A
Delta
B
Neutral Terminal
Enclosure bond
to safety
ground
Wye has high resistance neutral
grounding or is essentially ungrounded
12,470V
Utility
Distribution
Transformer
A
480V
Neutral
B
277V
Building Neutral
C
Safety Ground
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
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32
Ground Fault Overvoltage Issues
Subtransmission source transformer acts as grounded source
suppressing ground fault overvoltage on subtransmission until
subtransmission breaker opens.
Utility System
Bulk Source
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!
Feeder
Breaker
Subtransmission
Breaker
Subtransmission
(46kV)
Ground
Fault
DG
12.47 kV Line
Ground
Fault
Distribution
Substation
Transformer Acts as
ungrounded source
(not effectively
grounded)
Distribution
Substation
DG Site 1
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
Load
DG
Distribution
Substation
Load
Load
Load
Load
Neutral is Ungrounded
or High Z Grounded
Need enough load on this island with respect aggregate DG
at distribution level to suppress overvoltage – otherwise
effective grounding or other solutions are needed!
Need enough load on this island with respect aggregate
DG at all connected distribution substations to suppress
overvoltage – otherwise special solutions are needed!
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33
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.
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34
How Load Reduces
Ground Fault Overvoltage
Vag Before the
Fault
Vag
Neutral
Neutral
Vcg
Voltage
Increases
on Vag, Vbg
Vbg Vcg=0
For inverters the
excessive load will
also trigger fast
shutdown to protect
transistors
During Ground Fault
(light load)
X
R
Vbg
Impedance of DG
Source, its transformer
and connecting leads
Vag During Ground Fault
(heavy load)
12.47 kV Feeder
Neutral
Vcg=0
Vbg
Utility Source
Open
Breaker
Load
Ground Fault
(phase C)
Voltage does not rise much on Vag, Vbg because the overall size of the
triangle has been reduced (phase to phase voltage has dropped)
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35
Grounding Transformer Impedance Sizing
Utility Source
Open
Xt=5%
X1PV = 30%
IEEE Effective Grounding Definition
X 0 groundbank
Utility
Primary
Feeder
Inverter
Grounding
Transformer
Bank
X 1 pv
R0 groundbank
X 1 pv
3
1
X0groundbank, R0groundbank
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%).
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Engineering Targets to Provide Effective
Grounding with Reasonable Margin
X 0 groundbank
X 1 pv
R0 groundbank
X 1 pv
2
 0. 7
36
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.
Prepared by Nova Energy Specialists, LLC
I0 Total
I0 utility
Utility
Source
Path
I0 Ground transformer
Grounding
Transformer
Path
Zero Sequence Current Divider
37
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.
Waveform shown is Rotating
Machine Type Overvoltage
EMTP Simulation of Ferroresonant
Overvoltage
Load rejection, ground fault and
resonance related overvoltage
Unfaulted Phase Voltage
Normal Voltage
Prepared by Nova Energy Specialists, LLC
Breaker Opens (island forms)
38
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.
Prepared by Nova Energy Specialists, LLC
39
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
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.
Prepared by Nova Energy Specialists, LLC
41