Neutral Connections and
Effective Grounding
Introduction
Neutral connections and effective grounding are not recommended to
mitigate temporary overvoltage when using listed photovoltaic inverters.
Millions of dollars are being wasted because power companies are attempting
to mitigate temporary overvoltage (TOV) from photovoltaic inverters
using techniques designed for synchronous generators. This paper lays out
fundamental differences between the two power generation technologies
and associated differences in line-to-ground voltage during faults. It explains
why IEEE 142 “effective grounding” requirements do not work in PV inverter
systems and proposes a sound, cost-effective way to ground PV systems.
After modeling distribution-connected photovoltaic power systems, focusing
on TOV during line-to-ground faults on both the distribution line and the
low-voltage customer system, this paper examines how various configurations
of distribution transformers and grounding of the inverter isolation
transformer affect TOV. Laboratory tests validate the modeling.
Temporary Over-Voltage
Temporary overvoltage (TOV) poses a serious hazard to equipment
connected to a power grid. TOV can occur during a ground fault such as a
tree limb falling on a power line. In distribution and transmission lines fed by
synchronous generator power sources, utilities traditionally have mitigated
this danger using a technique called IEEE 142 “effective grounding.” In their
efforts to maintain safe and reliable power systems, utilities have attempted
to apply the same standard to photovoltaic inverter-based generation.
However, it is impossible to make a PV system comply with IEEE 142 as
currently written. The attempt to do so diminishes the effectiveness of
utilities’ protective systems and wastes power and money.
The different causes of TOV must be delineated in order to evaluate the
effectiveness of applying those standards in PV systems.
CONTENTS
•Introduction
Page 1
•Temporary Over-Voltage
Page 1
•TOV Mechanisms
Page 2
•Important Mechanism of
TOV in PV Systems
Page 2
•IEEE 142 Effective Grounding
Page 3
•Differences Between Generators and Inverters
Page 3
•Neutral Connection Generators vs Inverters
Page 3
•Why Most Inverters Do Not
Have a Solid Neutral Connection
Page 4
•Current Source vs Voltage Source Generation
Page 4
•Switching High Generation
Into Light Load
Page 5
•Overmodulation or Current
Control Saturation
Page 6
•Conclusion
Page 6
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TOV Mechanisms
The mechanisms that cause TOV can be divided into six categories:
i
1 Ground potential rise
2 Derived neutral shift
3 Inductive coupling of fault currents
4 High generation to load ratio
5 Interruption of inductive currents
6 Over-modulation / saturation of current controls
Ground potential rise occurs when large currents flow into grounding electrodes. The resistance between the
grounding electrode and “remote earth” results in a voltage rise between the local ground reference and other more
distant ground references.
Derived neutral shift occurs when one phase of a
distribution line is faulted to ground. If the substation breaker
opens in response to the fault, the distribution lines lose
their ground reference and the phase conductors float with
respect to ground. If the distribution line is being backfed
by a synchronous generator, the phase-to-phase voltage is
maintained even when one of the phases is at zero potential
to ground. For the unfaulted phases, that means the phase-toground voltage (and therefore the phase-to-neutral voltage)
can be the same value as the phase-to-phase voltage. In other
words, the neutral point can shift so that the phase-to-neutral
voltages on the unfaulted phases are equal to the phase-tophase voltage.
Figure 1 - Illustration of derived neutral shift.
When derived neutral shift occurs, devices connected phase-to-neutral or phase-to-ground can be subjected to as much as
1.73 times their rated voltage. The condition can persist until the fault clears, the distributed generation source trips off line,
or protective devices separate the generation source from the fault. The “effective grounding” standards in IEEE 142 are
primarily designed to mitigate this TOV mechanism.
Inductive coupling of fault currents in faulted phases or the neutral and unfaulted phases can induce voltages
in the unfaulted phases. Because fault currents supplied by central generation can be so large, inductive coupling is the
dominant TOV mechanism during a line-to-ground fault while the substation breaker remains closed. Once the substation
breaker opens, TOV is dominated by other mechanisms.
High generation to load ratio, also known as load rejection, occurs when a significant portion of the load becomes
separated from the generation source. If a switch, breaker or line-sectionalizing device opens, and the remaining connected
load is lower than the output of the distributed generation system, a voltage rise can occur.
Over-modulation can occur during load rejection when the inverter current control loop saturates, or goes to a
maximum duty cycle, leaving the (typically IGBT) switches “on” for long periods. Under these conditions, the output
voltage can approach the open-circuit voltage of the DC source times the transformer (if present) winding ratio. This can
be a very high voltage, on the order of 1.5 to 3 times the nominal peak instantaneous AC output voltage. If present, this
condition would persist until the inverter trips off due to phase overvoltage. However, most inverters have protections
against this possibility.
Important Mechanisms of TOV in PV Systems
Work by Michael Ropp at Northern Plains Power Technologies showed that the dominant TOV inducing mechanisms in
distributed generation systems are mechanisms 2 (derived neutral shift) and 4 (high generation to load ratio). Because it is
relevant to the topic of TOV, current control saturation will also be discussed. What remains to be seen is whether or not
synchronous generator “effective grounding” techniques mitigate TOV when applied to PV systems.
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IEEE 142 Effective Grounding
IEEE 142 (the “Green Book”) is a well-established standard that describes how to ground industrial and commercial power
systems. This standard provides the following definition for providing “effective grounding” of generators:
The zero sequence reactance of the grounding source must be positive and greater than three times the positive sequence
reactance of the generator. In addition, the zero sequence resistance of the grounding source must be positive and greater
than the source reactance of the generator.
It is clear from the text of the standard that it was intended to be applied to rotating machine generators. Significant
problems arise when attempting to apply IEEE 142 “effective grounding” when the generation source is an inverter.
Differences Between Generators and Inverters
The physical characteristics of inverters are very different
from those of generators. Generators have large reactance
because they are constructed from massive coiled conductors
with magnetic cores. The typical X/R ratio for a generator is
on the order of 30 to 50. For this reason, the restive portion
of a typical generator impedance is ignored because it is so
small when compared to the reactance. By contrast, inverters
have essentially no reactance. Only the relatively small choke
inductors and the isolation transformer leakage inductance
contribute any positive reactance to the circuit characteristics.
Figure 2 - Typical PV inverter equivalent circuit.
If some basic assumptions are made based on their short circuit characteristics, it can reasonably be approximated that
a typical PV inverter has an X/R ratio of 0.02 to 0.05. It would therefore be reasonable to ignore the reactive portion of
inverter impedance. The reactance of a typical PV inverter is essentially zero.
Based on their short circuit current characteristics, the resistive portion of inverter impedance would then have to be quite
high to explain their relatively low output fault current (in the range of 1 - 2pu). Typical resistive impedance values are in
the range of 0.5 - 1.5pu.
If we attempt to strictly satisfy the “effective grounding” equations from IEEE 142 using inverter reactance values, the
equations become mathematically impossible to solve:
The equations would have to be modified to have any kind of logical application to PV systems: The IEEE 142 “effective
grounding” standard cannot be applied to PV inverters in a straightforward fashion. This raises the question of whether
“effective grounding” is even applicable to inverters.
Neutral Connection – Generators vs Inverters
Synchronous generators are grounded by making a solid (low-impedance) connection between the generator neutral and
ground. However, no inverter with a solid neutral connection – that has been fully tested and listed to standard UL 1741
in this configuration - is offered for sale in North America. This begs the question, why do inverters not have solid neutral
connections?
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Why Most Inverters Do Not Have a Solid Neutral Connection
Photovoltaic inverters are designed and intended to operate as balanced, 3 phase current sources. Therefore, a neutral
conductor is not necessary for the export of power. Since the neutral conductor is not actually necessary, most inverters do
not even have terminals for a neutral conductor.
Even inverters which measure voltage phase-to-neutral do not have solid connection between the isolation transformer
neutral output and the neutral terminal. Where a connection between the neutral terminal and isolation transformer
exists, there is a neutral grounding resistor in series with the connection.
The temptation would be to simply remove the neutral grounding resistor or add a solid neutral connection and thus
render the inverter “effectively grounded”. The reason this is not offered as an option by inverter manufacturers is this
modification would make it very difficult to comply with the UL 1741 standard.
The most important reason inverters do not have solid neutral connection is prevent minute, short duration imbalances in
phase switching times from leading to unwanted neutral currents in the output. Allowing the isolation transformer neutral
to “float” prevents these disturbances from causing harmonic distortion in the host electrical system. ii This harmonic
distortion would make it extremely difficult for an inverter with a solid neutral connection to meet the harmonic distortion
requirements of the UL 1741 standard.
Additionally, a solid neutral connection can interfere with the inverter’s ability to detect phase voltage problems, and lead
to unwanted nuisance currents in the isolation transformer. Extensive design modifications and testing would be required
to overcome these problems.
Given the difficulties associated with adding a solid neutral connection, it is worth ascertaining whether or not there is any
real benefit to having a solid neutral connection in an inverter.
Current Source vs Voltage Source Generation
Correctly predicting TOV in power systems with PV inverters requires an understanding of how inverters function. Most
PV inverters manufactured for use in North America are certified by a Nationally Recognized Testing Laboratory (NRTL)
to comply with safety standard UL 1741, which requires compliance with IEEE 1547, the standard for distributed generation.
The IEEE standard prohibits “active voltage regulation at the point of common coupling.” Inverter manufacturers (including
Advanced Energy) interpret that clause to mean that listed, grid-interactive inverters cannot be operated as voltage sources.
Therefore, listed PV inverters are carefully designed to operate as current sources into the existing voltage on the grid.
Any attempt to predict power system behavior with PV inverters must incorporate this fundamental property of inverters.
Under normal operation, phase voltage is set by central generation
(usually a synchronous generator) on the grid. The inverter will act
as a current source into the connected grid impedance. As a result,
the inverter will load share with the grid power source. Typically, the
grid and load impedances assure that the inverter power is utilized
by the locally connected load.
One important implication is that (during an island powered only by
a current source inverter) the phase-to-neutral voltage will simply
be the product of the phase current times the connected phase-toneutral load.
PV plant
terminals
PV plant
Ia
Ic
+
+
Feeder series
impedance
Van
n
-
Van’
n’
-
Ib
Delta-connected Y-connected
load
load
Figure 3 - Current source equivalent circuit.
n
+
4
Vcn
+
+
Van
Van
--
Vbn
+
+
Vcnn
Unlike a synchronous generator, a PV inverter has no mechanism for
maintaining phase-to-phase voltage. Consequently, during a fault, the phase to
neutral voltages will shift according to the change in impedance introduced by
the fault.
-
Vbn
+
Figure 4 - Illustration of current source generation phase-neutral voltage during line
to ground faults.
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Thus, we would not expect to see TOV mechanism #2, derived neutral shift, during line-to-ground faults being fed by PV
generation. Of course, power systems are complex, and this hypothesis should be tested by simulation and scrutiny of the
circuit theory.
Extensive simulations were performed to see whether a solid neutral connection for the inverter isolation transformer
would mitigate TOV. iii As predicted, grounding the inverter isolation transformer does not mitigate TOV. This conclusion
was supported regardless of the winding configuration of the inverter isolation transformer, the winding configuration of the
distribution transformer, or whether the fault was on the distribution line or the low-voltage customer system.
Figure 6 - Results showing no improvement in TOV with
inverter isolation transformer solid neutral connection for
L-G faults on the customer low voltage system.
Modeling results were confirmed in two ways. First, the
distribution line modeled in the study was based on a welldocumented real feeder for which extensive validation data is
available. Second, the results of laboratory experiments closely
agreed with the modeling of faults on the low-voltage customer
system. Differences between the modeled and measured values
were due to parasitic resistances in the inductive and capacitive
components of the load.
Figure 7 (on the right) - Comparison of experimental (dots) and simulated
(thin solid lines) voltage waveforms during model validation testing.
Differences were due to parasitic resistances in the reactive elements
of the connected load.
Voltage (V)
Figure 5 - Results showing no improvement in TOV with
inverter isolation transformer solid neutral connection for
L-G faults on the distribution line.
Simulated and experimental inverter terminal voltages, no neutral, with parasitic Z
800
Sim A
Sim B
600
Sim C
Exp A
400
Exp B
Exp C
200
0
-200
-400
-600
-800
6.98
6.99
7
7.01
Time
7.02
7.03
7.04
Switching High Generation Into Light Load
Ohm’s law explains TOV mechanism #4. When the operation of a
breaker or line sectionalizing device removes a large por tion of the
connected load, all the inver ter current will flow into the remaining
connected load. If the load is less than the PV system output, voltage
will temporarily rise until the inver ter protective functions are
triggered.
The modeling results show conclusively that ratio of generation to
load has a significant impact on the level of TOV, with significant TOV
occurring where generation exceeds load. iv
Figure 8 - Illustration of switching high generation into light load.
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Overmodulation or Current Control Saturation
The current control loop in PV inverters is designed to maintain a constant output current at the array maximum power
point. Sudden changes in the AC load, such as very large reductions in connected load, can cause the PWM duty cycle to
go to its maximum value as the current controls work to maintain the AC output current at a steady value. This results in
a modified square wave AC output (also referred to as “six stepping”), characteristic of older variable-frequency drives.
In these cases, the AC output waveform becomes distorted, and the AC output voltage can rise to the array open-circuit
voltage or higher.
The literature has addressed concern about TOV when the
current controls saturate for more than a decade. The 2002
Australian PV interconnect standards required a test for this
condition. In Spain, instances of equipment being damaged
by this mechanism of TOV were published in 2009. Southern
California Edison began testing inverters for this behavior in
2010 and published results of laboratory tests demonstrating
the phenomenon in 2011.
Inverters operating in the overmodulation state become voltage
sources and can therefore give rise to an additional mechanism
of TOV: mechanism # 2, derived neutral shift. For this reason,
it is recommended that grounding transformers be used with
inverters prone to this condition.
Fortunately, this behavior is easy to prevent with appropriate
design. All of the AE TX model inverters limit overmodulation
when the AC output experiences a loss of load.
Figure 9 - Typical AE TX model inverter AC output voltage
after 100% loss of load.
Conclusions
Solidly grounding the neutral of an inverter isolation transformer does not mitigate TOV. In addition, there are numerous
technical and regulatory problems associated with this type of neutral connection. For these reasons, a solid neutral
connection should not be required for listed, current-source PV inverters. In addition, no inverter with a solid neutral
connection should be permitted used unless it passes all of the required tests for certification to UL 1741.
Inverters that operate as controlled-current sources under fault conditions - including short circuit and 100% load rejection
- do not cause TOV mechanism #2, derived neutral shift. Accordingly, neither a solid neutral connection nor external
grounding banks are warranted for inverters of this type. Research demonstrating these findings has been peer-reviewed at
two technical conferences and by numerous electric power industry professionals. In addition, Advanced Energy can supply
data which demonstrates that inverters of the AE TX line (formerly sold under the brand name PV Powered) operate as
controlled-current sources under fault conditions. Therefore, neither solid neutral connections nor external grounding banks
are warranted for PV systems utilizing AE TX model inverters.
High load to generation ratio very effectively reduces the likelihood of TOV. Caution is warranted with PV systems where
the generation to load ratio can be close to or greater than 1. “Effective grounding” does not mitigate this type of TOV.
This does not imply that PV systems should never be interconnected via transformers with delta windings on the
distribution line side. When the connected load is much greater than the PV generation, there is neither a phase-to-phase
voltage source mechanism nor sufficient available energy to drive the unfaulted phases up to damaging voltage levels.
TOV is mitigated when the distribution transformer that connects a PV system to the transmission line to a grid is grounded
Wye on the distribution line side. Caution and further study is warranted when considering interconnecting PV systems
through distribution transformers that have delta windings on the distribution line side.
The data also show that TOV due to line-to-ground faults in the low-voltage customer system is dramatically higher when
the distribution transformer has a delta winding on the low-voltage side. Distribution transformers with Yg connections on
the distribution side and delta windings on the customer side will also desensitize ground fault detection by the area EPS.
For these reasons, distribution transformers with delta windings on the low-voltage side are not recommended.
6
Distribution transformers with Yg : Yg windings are recommended with PV systems.
White Paper
M. E. Ropp, M. Johnson, D. Schutz, S. Cozine,
“Effective grounding of distributed generation inverters may not mitigate transient and temporary overvoltage”
39th Annual Western Protective Relay Conference, October 16-18, 2012, p. 1
i
M. E. Ropp, M. Johnson, D. Schutz, S. Cozine,
“Effective grounding of distributed generation inverters may not mitigate transient and temporary overvoltage”
39th Annual Western Protective Relay Conference, October 16-18, 2012, p. 2
ii
M. E. Ropp, M. Johnson, D. Schutz, S. Cozine,
“Effective grounding of distributed generation inverters may not mitigate transient and temporary overvoltage”
39th Annual Western Protective Relay Conference, October 16-18, 2012, p. 5-8
iii
M. E. Ropp, M. Johnson, D. Schutz, S. Cozine,
“Effective grounding of distributed generation inverters may not mitigate transient and temporary overvoltage”
39th Annual Western Protective Relay Conference, October 16-18, 2012, p. 5-8
iv
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