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-VoltageTemporary 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.

Neutral Connections and Effective Grounding

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 MechanismsThe 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 f low 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 f loat 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-to-ground 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-to-phase voltage.

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 signif icant 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 SystemsWork 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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Figure 1 - Illustration of derived neutral shift.

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IEEE 142 Effective GroundingIEEE 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. Signif icant problems arise when attempting to apply IEEE 142 “effective grounding” when the generation source is an inverter.

Differences Between Generators and InvertersThe 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.

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 modif ied 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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Figure 2 - Typical PV inverter equivalent circuit.

Why Most Inverters Do Not Have a Solid Neutral ConnectionPhotovoltaic 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 modif ication would make it very diff icult 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 “f loat” prevents these disturbances from causing harmonic distortion in the host electrical system.ii This harmonic distortion would make it extremely diff icult 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 modif ications and testing would be required to overcome these problems.

Given the diff iculties 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 GenerationCorrectly 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 certif ied 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-to-neutral load.

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.

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Figure 3 - Current source equivalent circuit.

Ic

Ia

IbDelta-connected

loadY-connected

load

+

Van’

-

Feeder series impedance

PV plant

n

n’

+ Van -

PV plant terminals

+

Van

-- Vbn +

- Vcn +

n

+

Van

-- Vbn +

- Vcn +

n

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.

Modeling results were confirmed in two ways. First, the distribution line modeled in the study was based on a well-documented 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.

Switching High Generation Into Light LoadOhm’s law explains TOV mechanism #4. When the operation of a

breaker or line sectionalizing device removes a large portion of the

connected load, all the inverter current will f low into the remaining

connected load. If the load is less than the PV system output, voltage

will temporarily rise until the inverter protective functions are

triggered.

The modeling results show conclusively that ratio of generation to

load has a signif icant impact on the level of TOV, with signif icant TOV

occurring where generation exceeds load.iv

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Figure 5 - Results showing no improvement in TOV with inverter isolation transformer solid neutral connection for L-G faults on the distribution line.

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.

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. 6.98 6.99 7 7.01 7.02 7.03 7.04-800

-600

-400

-200

0

200

400

600

800

Time

Volta

ge (V

)

Simulated and experimental inverter terminal voltages, no neutral, with parasitic Z

Sim ASim BSim CExp AExp BExp C

Figure 8 - Illustration of switching high generation into light load.

Overmodulation or Current Control SaturationThe 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 modif ied 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.

ConclusionsSolidly 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 certif ication 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 f indings 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 suff icient 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.

Distribution transformers with Yg : Yg windings are recommended with PV systems.

Figure 9 - Typical AE TX model inverter AC output voltage

after 100% loss of load.

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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. 1ii 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. 2iii 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. 5-8iv 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

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