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POWER TRANSFORMER NEUTRAL GROUNDING REACTOR APPLICATION AND
DISTRIBUTION FEEDER PROTECTION ISSUES AT CENTERPOINT ENERGY
Patrick Sorrells and Alberto Benitez
CenterPoint Energy
ABSTRACT
This paper discusses the ramifications of grounding a
substation power transformer through a reactor on the
CenterPoint Energy distribution system. The purpose of
the reactor is to reduce the magnitude of ground fault
currents. This is expected to increase transformer life
expectancy by significantly reducing transformer short
circuit forces. The higher ground impedance provided by
the Neutral Grounding Reactor (NGR) also causes an
increased voltage drop in the ground return path, raising
the temporary overvoltage on the unfaulted phases and
deepening the voltage sag on the faulted phase during a
ground fault. Under normal operating conditions with
large load imbalances, voltage regulation can be also
impacted. The reduction in ground fault current requires
the modification of ground protective device coordination
and settings. The paper discusses how these issues are
addressed for a successful implementation of an NGR in
an effectively grounded, 4-wire distribution system.
1. INTRODUCTION
From 1989 to 1996, CenterPoint Energy experienced an
usually high number of failures among its substation
power transformers. A total of 36 power transformers
failed during this time. The single largest cause of failure
was through faults, accounting for 36% of all failures.
Through faults are faults that occur on the distribution
system. These faults can stress the power transformers
windings since the windings must carry an unusually
high current magnitude while the fault persists.
Given the expense of replacing power
transformers - transformers account for two-thirds of the
cost of a substation CenterPoint Energy formed a team
to make recommendations for reducing failures from
these faults. One of the ideas suggested was the
installation of a Neutral Grounding Reactor (NGR)
between the transformer neutral bushing and the system
ground. Grounding a power transformer through an NGR
increases the impedance of the system ground, lowering
the magnitude of ground fault currents. The decreased
fault current magnitude reduces the mechanical stress on
the transformers windings. This should result in fewer
transformer failures from through faults.
All of CenterPoint Energys power transformers
are core form, two winding units connected delta on the
high side and grounded wye on the secondary side. The
secondary side is energized at either 12.47kV (12kV) or
34.5kV (35kV) and serves 4-wire, multigrounded
distribution feeders. Prior to 1996, all of the transformers
had their neutral bushing bonded directly to the
substation ground mat. No impedance was intentionally
added.
In 1996, CenterPoint Energy began a pilot
project at its Westfield substation. The four power
transformers at the substation two serving 12kV feeders
and two serving 35kV feeders were grounded through
NGRs. The intention was to collect data on how the
NGRs impacted the distribution feeders. However,
equipment problems and personnel changes caused the
project to languish.
Since that time, overall power transformer
failures have decreased to 21 while the transformer fleet
itself has increased. But through fault failures remained
steady in absolute terms 11 transformers - and rose as a
percentage of all failures to 52%. The continued
prevalence of through fault failures renewed interest in
NGRs. Around the same time, concern was voiced about
the possible effects on the distribution system. Voltage
regulation, power quality, protective device coordination,
and ground fault protection are all impacted to a greater
or lesser degree. In addition, the NGR changes some of
the standard assumptions used for setting the feeder
relays at CenterPoint Energy. This paper presents these
issues as they relate to CenterPoint Energys system and
discusses data collected from the Westfield project since
2001.
2. EFFECT OF A NEUTRAL GROUNDING
REACTOR
A NGR is an inductor intentionally inserted between the
substation transformers neutral and the system ground.
The impedance of the NGR adds to the impedance of the
grounding system, raising the total impedance that
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ground currents must flow through. Since the magnitude
of a fault current is determined by dividing the system
voltage by the impedance of the path it flows through
(I=V/Z), the additional impedance reduces the magnitude
of the fault current. Note that only ground faults are
affected by a NGR.
To see how the NGR raises the impedance of the
fault path for ground faults, consider that all currents
whether load or fault - must flow in a loop and must
return to their source. For CenterPoint Energys
distribution system, that source is effectively the windings
of the substation transformer. During a line to ground
fault, current flows from the winding of the transformer,
through the phase conductor, into the earth. The current
will then split and flow through the neutral conductor and
the earth as it returns to the transformer. The current
returns to the transformer winding through the
transformers neutral bushing. Adding the NGR forces
all currents returning through the neutral and the earth to
pass through the NGR to return to the transformers
windings. Currents that do not have to flow through the
transformers neutral to return to the windings line to
line fault currents, for instance will not flow through
the NGR and are unaffected.
The reduction in ground fault current depends
on the relative magnitude of the NGR's impedance
compared to the impedance of the fault path without the
NGR and the fault type. For single line to ground faults
near the substation, the additional impedance the NGR
contributes to the fault path is large compared to the
existing impedance. A dramatic reduction in the fault
current can be achieved. For single line to ground faults
located at the end of the feeder, the additional impedance
the NGR contributes to the fault path is small compared
to the existing impedance to the fault. The NGR will
reduce these fault currents, but only slightly. The NGRs
effect on double line to ground faults is also greatest for
faults near the substation and least for faults near the end
of the feeder. However, increasing the ground impedance
makes these faults appear more like a line to line fault.
This can reduce the line current magnitude seen at the
transformer, but the change is generally not significant.
The NGRs effect on the ground fault current is
not limited to the symmetrical AC current. For faults that
are initially asymmetrical a DC offset current exists -
the rate of decay of the DC offset current decreases
because the NGR increases the X/R ratio of the system.
Effectively, the DC component of the fault current
remains at a higher value for longer, relative to the AC
component, than would occur otherwise without the
NGR. The change in the DC offset partially cancels some
of the reduction in fault current magnitude while it exists.
However, the reduction in ground fault current magnitude
dominates the slower decay of the DC offset for all points
on the feeder. As expected, the NGRs effect on the X/R
ratio is greatest for ground faults near the substation and
least for ground faults at the end of the feeder.
Practical considerations limit the amount of fault
current reduction that can be achieved. The most
important of these is the voltage rating of the lightning
arrestors used on the feeder. Lightning arrestors rated for
line to neutral voltages, as opposed to line to line
voltages, can only be used on effectively grounded
systems [1]. An effectively grounded system is defined as
having an X0/X1 ratio of 3 or less and a R0/X1 ratio
between 0 and 1[1]. Here, R0 and X0 represent the zero
sequence resistance and reactance of the distribution
system at any given point; X1 represents the positive
sequence reactance of the distribution system at that same
point. The impedance of the NGR adds to the zero
sequence values, but not the positive sequence values.
Since the NGRs impedance is predominantly reactive, its
primary effect is to raise the X0 value for all points on
the
distribution system. The resistance of the NGR is
generally small enough that its effect on the R0/X1 ratio
can be ignored. Since all of CenterPoint Energys existing
lightning arrestors are rated for line to neutral voltages,
an effectively grounded system must be maintained.
Thus, the size of the NGR that can be installed is limited
by the requirement to maintain an X0/X1 ratio of 3 or
less. Given this requirement, the single line to ground
fault current can be limited, at best, to 60% of the value
of the three-phase fault current.
3. THE SHORT CIRCUIT STRENGTH OF
TRANSFORMERS
The significance of reducing the fault current magnitude
lies in its relationship to the mechanical forces
experienced by the winding during a fault. The
mechanical forces acting on the windings are
proportional to the square of the fault current magnitude
[2]. Thus, when the fault current magnitude doubles, the
mechanical forces in the transformer increase by a factor
of four. Physically, these forces act to crush, bend, or
stretch the conductors and their associated
insulation.[3]. The short circuit strength of a
transformer is its ability to withstand these effects.
The design and construction of the transformer
determine its initial short circuit strength. Once it is
placed in service, the transformers ability to retain its
short circuit strength is predominantly a function of the
clamping pressure on the windings [4]. The clamping
pressure is intended to keep the windings securely in
place during faults so that they do not move from their
original placement [4]. As long as the windings are
properly aligned, the mechanical forces that act on them
during a fault can be minimized [5]. However, if they are
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allowed to move slightly, the forces exerted on the
windings will grow rapidly [2], [5]. Once some small
movement has occurred, the effect tends to accelerate
the forces increase, causing the windings to move a little
more, causing the forces to increase further, etc.
Eventually, either the windings will become deformed
and/or collapse or an insulation rupture will occur [5],
[6].
Not surprisingly, the clamping pressure and
thus the transformers short circuit strength - will not
remain constant over time [6]. Changes in the thickness
of the winding insulation or the end insulation will cause
the clamping pressure to vary [4]. Both insulation aging
and the mechanical forces associated with faults can
gradually reduce the clamping pressure, while short term
environmental effects can cause a temporary increase in
clamping pressure [6], [4]. Each of these processes is
discussed below.
3.1. Insulation Aging
The primary reason the transformers short circuit
strength does not remain constant is the aging of the
cellulose insulation [6]. The cellulose insulation
physically changes in several ways while a transformer is
in service. First, the aging process breaks down the
chemical bonds that give the insulation its tensile
strength its ability to resist being torn [6]. As the
insulation weakens, it becomes more susceptible to
tearing when stressed by the mechanical forces of a fault.
If it does tear, the result will be a new fault internal to
the
transformer that will very likely lead to a failure.
The same process that breaks down the
insulations tensile strength also causes the cellulose to
decompose, so that less material physically exists over
time [4]. As noted above, a change in the insulation
thickness will cause a change in the clamping pressure.
In this case, the loss of insulation will cause a loss of
clamping pressure. The reduction in clamping pressure
increases the chances for winding movement and,
eventually, a failure due to the increased forces acting on
the winding.
Finally, the clamping pressure itself causes the
cellulose to relax and settle [6]. The clamping pressure
acts as a load on the insulation, compressing it. When
the insulation is compressed over a long period of time, it
develops a permanent set. Even if the compressive force
is reduced or removed, the insulation will not recover to
its original size. Although manufacturers specially pre-
treat the insulation to reduce the amount of settling as
much as possible, it cannot be completely eliminated [4].
Thus, due to the clamping pressures action on the
insulation, it is impossible to maintain the initial
pressure
on the windings. As noted above, the chance of an
internal failure increases as the clamping pressure
decreases.
3.2. Fault Forces
The forces associated with faults can also erode the
transformers short circuit strength over time. Similar to
the relaxation and settling caused by the clamping
pressure, the fault forces act to compress the winding
insulation as well [6], [5]. Unlike the clamping pressure,
the fault forces apply a compressive force that rapidly
builds and diminishes as the sinusoidal instantaneous
magnitude of the fault current changes during each cycle.
The overall result is the same the insulation develops a
permanent set that causes a reduction in clamping
pressure.
Although there seems to be general agreement
that fault currents can degrade the short circuit strength
of a transformer and that their effects are cumulative, the
exact fault current magnitudes and duration at which
these effects occur are not clear [2], [5], [6], [7].
3.3. Short Term Effects
In the long term, insulation aging and the fault forces will
cause a decrease in clamping pressure. In the short term,
however, it is possible for the insulation to expand,
causing a temporary increase in clamping pressure.
Often, the same factor that accelerates aging over the
long term causes a short-term benefit.
Prevost [4] has shown that the thermal
coefficient of expansion for cellulose is roughly three
times higher than for the conductor in the winding and
the steel in the clamping system. The thermal coefficient
of expansion for the conductor and the steel is roughly the
same. High temperatures, therefore, cause the insulation
to expand more than the conductor and the steel,
increasing the clamping pressure. Because of this effect,
Prevost believes that transformers are less likely to fail
due to faults during periods of high loading as opposed to
periods of lighter loading.
Prevost has also shown that moisture causes the
cellulose to swell. Again, this causes the expansion of the
insulation, increasing clamping pressure. However,
moisture also acts as a catalyst in the aging process. As
the insulation decomposes, it releases moisture into the
transformer. In general, the aging process releases more
moisture than consumed so that there is a net increase in
the amount of moisture. In terms of the clamping
pressure, Prevost is uncertain which process dominates
the increase in pressure due to more water absorption by
the insulation or the decrease in pressure due to the
increased aging rate.
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3.4. Impact of a Neutral Grounding Reactor
From the discussion above, it should be clear that several
factors influence the short circuit strength of the
transformer once it enters service. While it is possible to
have a short term increase in the short circuit strength,
over the long haul the short circuit strength of the
transformer will decrease. As it decreases, a fault that
might have been successfully survived previously may
now be severe enough to result in a failure. To extend the
transformers life, its short circuit strength must be
maintained at a higher level for a longer period of time or
the fault forces it is subjected to must be reduced.
The NGR accomplishes both of these. The
erosion of short circuit strength slows since the NGR
reduces the ground through fault forces to much less than
they would be otherwise. In addition, the likelihood of a
failure from any given ground through fault is decreased
since the short circuit strength of the transformer need
not be as high to prevent a failure. Although the NGR
only significantly affects line to ground faults, these
faults
represent approximately 70% of the all the faults the
transformer will see [8]. Thus, the NGR offers an
attractive way to decrease the failure rate of transformers.
4. THE NGR AND THE DISTRIBUTION SYSTEM
While the NGRs impedance can be beneficial in
extending transformer life expectancy, it also has
repercussions on the distribution system. Grounding the
power transformer through a reactor causes two main
effects - it increases the neutral shift produced by current
flowing through the system ground and it reduces the
ground fault current magnitude. The impact of each of
these issues on CenterPoint Energys distribution system
is discussed below.
4.1. Voltage Regulation
Unbalanced loading on the phases of the distribution
system will cause a current to flow in the neutral. With
the installation of a NGR, this unbalanced current will
now flow through the NGRs impedance. The voltage
developed across the NGR will cause the neutral point
between the phases to shift. Depending on the direction
the neutral shifts which is governed by the angle of the
neutral current each line to neutral voltage will be
higher or lower than before. Note that the neutral current
that flows through the NGR is the result of the
unbalanced loading on all the feeders tied to that
transformer.
CenterPoint Energy regulates the distribution
voltage by monitoring the C phase voltage at the
secondary side of the transformer. The transformers
Load Tap Changer adjusts the taps to keep this voltage
within a specified bandwidth. This system will regulate
the voltage adequately for all three phases as long as the
phases remain reasonably balanced. This will continue to
be true as long as the magnitude of the transformers
neutral current remains low. However, at higher
magnitudes, the neutral shift may become significant.
High neutral currents could result in high or low voltages
on A and/or B phases the tap changer would adjust to
keep the C phase voltage within the specified bandwidth.
Despite the possibility of a problem, the
likelihood of it occurring appears quite low. Monitors
installed as part of CenterPoint Energys Westfield
Project, discussed later in this paper, recorded no
instances of high or low voltage that were attributable to
the NGR.
If a problem arises, only certain types of
customers will be affected. Single-phase customers on A
or B phase may see a high or low voltage condition.
Three-phase customers served from a transformer bank
with a closed delta connection on the high side will not
see any problems, because the line to line voltages on the
distribution system will not be affected by a neutral shift.
Three-phase customers served from a grounded wye
connection on the high side may experience a voltage
problem with single-phase loads, but three-phase loads
would not be affected. Customers served from an open
wye-open delta bank could experience problems with both
their single-phase and three-phase equipment.
There are several possible solutions if a high or
low voltage condition arises. The best solution is to
balance the loading on the transformer. Alternately, the
NGR could be purchased with a middle tap position so
that its impedance could be reduced. This, in turn,
reduces its voltage drop by half for a given amount of
neutral current. Another possibility would be to simply
bypass the NGR. This would completely eliminate any
voltage drop associated with its impedance. The danger
in not balancing the circuit is that both the alternate
solutions reduce or eliminate the benefits of the NGR.
Nonetheless, they provide a way to address a voltage
regulation issue associated with the NGR quickly.
4.2. Increased Temporary Overvoltage on Unfaulted
Phases
Just as unbalanced current can cause a neutral shift, so
too does ground fault current. In this case, the neutral
shift causes the potential between the system ground and
the unfaulted phases to rise. The result is a Temporary
Overvoltage (TOV) that lasts until the ground fault is
cleared. The addition of the NGR's impedance increases
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the magnitude of the neutral shift, and thus the TOV on
the unfaulted phases.
An example may help clarify how the TOV has
risen if the ground fault current has been reduced.
Assume a line to ground fault occurs on Phase A of a
12.47kV distribution feeder. With no NGR installed at
the substation, assume that the single line to ground fault
current is 3600/-75 Amps. Now, assume the ground
impedance at the fault location is 0.5/75 ohms. The
voltage drop in the ground is 3600/-75 Amps * 0.5/-75
ohms = 1800/0 volts. The voltage from Phase B to the
ground is the system voltage minus the voltage drop in
the ground, which is 7200/120 1800/0 = 8248/131.
The Phase B to ground voltage has risen from 7200 volts
to 8248 volts. A similar result would be calculated for the
Phase C to ground voltage. The voltage drop in the
ground shifts the neutral away from Phases B and C,
increasing the voltage difference (TOV) between them.
Now add an NGR of 0.4 ohms at the
transformer. The single line to ground fault current for
the same fault at the same location becomes 3000/-80
Amps. The fault current has been reduced. However, the
ground impedance has increased to 0.9/80 ohms. The
voltage drop through the ground is 3000/-80 Amps *
0.9/80 ohms = 2700/0 volts. The Phase B to ground
voltage is now 7200/120 2700/0 = 8863/135. The
voltage has risen from 8248 volts to 8863 volts. The
NGR has reduced the current, but increased the neutral
shift.
For a solidly grounded, 4-wire, three-phase
distribution system designed with open-wire conductors,
the largest expected TOV generally has been considered
to be 1.20 per unit (pu)[9]. Since voltage regulation
allows the nominal system voltage to be 1.05, the
maximum expected TOV becomes 1.25pu (1.20*1.05, but
often rounded to 1.25). However, the actual maximum
TOV experienced on a feeder may be higher or lower
than this theoretical limit. Computer studies have shown
that a number of factors can impact the TOV the
impedance of the system neutral conductor, the number
and footing resistance of the pole grounds, and the
impedance of the substation grounding mat all have an
impact on the TOV [9], [10]. It may be possible to see
TOVs of 1.30pu or more in practice without installing an
NGR [9].
The addition of an NGR will cause these values
to rise. CenterPoint Energy modeled a typical 12kV and
35kV distribution feeder in Microsoft Excel and ATP
(Alternative Transient Program) to determine what the
maximum expected TOV would be. The simulations
assumed the largest possible NGR that allowed the system
to remain effectively grounded. The maximum TOV in
the simulations - 1.35pu - occurred on the 12kV feeder
with a single line to ground fault.
Any increase in the TOV must be considered in
light of the arrestors TOV withstand capabilities. Most
faults on the distribution system will last less than 10
cycles. Some faults could last much longer than this,
especially if a large fuse or a breaker operating on a CO-9
curve clears a low magnitude fault. However, a low
magnitude fault implies a lower TOV since the current
flowing through the system ground is less. For the
arrestors used by CenterPoint Energy, the TOV withstand
at 10 cycles for prior duty is approximately 1.6pu of the
Maximum Continuous Operating Voltage (MCOV) for
distribution class arrestors and 1.47pu of the MCOV for
riser pole arrestors. For faults lasting 1 second, the TOV
withstand is approximately 1.54pu and 1.41pu of the
MCOV, respectively. Since the worst case expected TOV
was 1.35pu, the increase in TOV levels caused by an
NGR should not be above the withstand levels of the
arrestors.
A second concern related to the elevated TOV is
its impact on customer equipment. Direct information on
the TOV withstand capabilities of customer equipment is
limited. In 1990, Northeast Utilities conducted a study in
which three types of typical consumer electronic devices
digital clocks, microwaves, and VCRs were subjected
to various power system disturbances to gauge their
response [11]. Ten devices of each type were tested. One
of the tests subjected the devices to a TOV of 1.22pu for
periods ranging from 0.5 to 120 cycles. The authors
noted that none of the devices showed any adverse effects
from the TOV testing. The study did not consider any
potential accelerated aging effects.
In lieu of direct evidence, utility operating
experience can provide an excellent guide to the implied
TOV withstand abilities of customer equipment. A
customers equipment should be able to withstand the
maximum TOV inherent in the utility systems used in the
United States. Previously it was noted that a solidly
grounded, 4-wire, three-phase distribution system with
open-wire conductors has a maximum expected TOV of
1.25pu. However, distribution systems utilizing spacer-
cable designs have a maximum expected TOV of 1.50pu
[12]. In addition, customer equipment installed on
ungrounded secondary systems (i.e. 480volt 3-wire) must
be capable of handling 1.82pu (1.05*1.73) during ground
faults until the fault is located and removed [12], [13].
This implies that, at a minimum, single-phase customer
equipment should be able to withstand a TOV of 1.50pu
while three-phase customer equipment should be able to
withstand a TOV of 1.82pu. This suggests that the increased TOV
should not have a significant impact on
customer equipment.
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4.3. Voltage Sags
When the neutral shifts during a ground fault, it not only
increases the potential difference between the system
ground and the unfaulted phases, it also decreases the
potential difference between the system ground and the
faulted phase. The result is a voltage sag on the faulted
phase. Not surprisingly, the NGRs impedance increases
the depth of the voltage sag experienced by customers
along the faulted phase.
Its depth and its duration typically characterize
the impact of a voltage sag. With an NGR, the depth of
the voltage sags seen by customers both on the faulted
feeder and those served by adjacent feeders from the same
transformer will increase. The NGRs impedance
essentially appears as an increase in the transformers
impedance. The combined transformer/NGR impedance
becomes a larger percentage of the total impedance of the
fault path, causing a larger percentage of the voltage drop
to appear across the transformer. The effect of the NGR
will be determined by its size relative to the total
impedance of the fault path. The duration of a voltage sag
could also be impacted by the NGR since most protective
devices operate slower for lower magnitude fault currents.
It is important to gauge these changes in the
context of the actual faults seen on the feeders. For
instance, data collected by CenterPoint Energy about
faults on its distribution feeders shows that approximately
70% of all faults lasted 3 cycles or less and approximately
17% of all faults lasted more than 11 cycles. Faults
lasting 3 cycles or less are either self-cleared or cleared
by
a fuse. The authors believe the duration of self-cleared
faults will not be affected by an NGR. For ground faults
cleared by fuses, the NGR will increase the operating
time. However, since these fuses are operating so quickly,
the NGR is likely to add only a cycle or two to the
clearing time. Faults lasting more than 11 cycles are
almost always cleared by the breaker. For customers on
the faulted feeder, the initial voltage sag associated with
a
fault will be followed by a complete outage when the
breaker opens. For customers served by the same
transformer but on a separate feeder from the faulted
feeder, the duration of the initial voltage sag will remain
the same. This occurs because the breakers first
operation is caused either by an instantaneous relay, not a
time overcurrent relay. Data collected by CenterPoint
Energy has shown that faults causing the breaker to
operate are cleared 70% of the time by the first breaker
operation.
This data suggests that the increased duration of
the voltage sags is unlikely to be an issue. Whether the
change in the depth of the voltage sags causes them to
move from an acceptable level to the customer to an
unacceptable level will depend largely on the type of
customers undergoing them. In the experience of the
authors, voltage sags are typically a concern only for
industrial customers and then only when these customers
are using sensitive computerized equipment. Nonetheless,
the general effect of an NGR will be to deepen and
prolong the voltage sags seen by the customer.
4.4. Protective Device Coordination
While the neutral shift impacts voltage regulation, TOV,
and voltage sags, it is the reduction in ground fault
current magnitude that affects the coordination of
protective devices on the distribution system. Since
CenterPoint Energy uses a fuse-blowing scheme for all its
distribution feeders, fuse to fuse coordination will
improve. The improved fuse to fuse coordination will
decrease the number of customers out of power during a
fault, improving SAIFI and CAIDI numbers. Conversely,
the coordination between a breaker or recloser and a fuse
will worsen, increasing the number of circuit operations
and reducing customer satisfaction.
Improved fuse to fuse coordination occurs
because of the way CenterPoint Energy sizes its fuses.
For transformer banks and the terminal poles for URD
(Underground Residential) loops, fuses are selected based
on the KVA of the transformer(s) to be protected - fault
current is not considered. These fuses are unaffected by
an NGR. However, for parent fuses - upstream fuses - the
available fault current is often the deciding factor in
determining what size the fuse should be. Although it is
possible for parent fuses protecting a two phase or three
phase line to see a line to line fault, fuses are sized to
coordinate for line to ground faults since these are the
most common. Parent fuses are sized to allow a child
fuse - a downstream fuse - time to operate in response to a
fault before the parent fuse operates. This minimizes the
number of customers out for a fault behind a child fuse.
Coordinating the parent and child fuses in this
manner is dependent on the speed at which the fuses
operate. Fuses operate very quickly for high magnitude
faults and much slower for low magnitude faults. At
higher fault currents, coordination between fuses becomes
very difficult since adequate time separation between the
fuse operations cannot be insured. Both the parent and
the child fuse may operate for a fault behind a child fuse.
Thus, the reduction in ground fault currents afforded by
the NGR makes it more likely that coordination between
the parent and child fuses can be obtained.
This same effect is what worsens coordination
with reclosers and breakers. CenterPoint Energy
instantaneously trips the feeder breaker for any fault
above 7200 Amps. On the first trip for a fault below
7200 Amps, the instantaneous trip is delayed, typically
for 10 cycles. This same general scheme is used for
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reclosers. The fuse must coordinate with this time-
delayed trip if an unnecessary operation is to be avoided.
With the NGR, the lower fault current magnitudes will
cause the fuses to take longer to operate. Thus, it
becomes more likely that the breaker or recloser will trip
for a fault behind a fuse.
Even without an NGR, it is possible for the
breaker or recloser to trip for a fault behind a fuse. With
the NGR, the point at which the breaker and fuse begin to
mis-coordinate moves closer to the substation because the
ground fault currents have been reduced along the feeder
(See Figure 1). More fuses will now fall into the mis-
coordination area, potentially increasing the number of
circuit operations. For example, assume a 12 kV feeder
where the breaker and a certain size fuse do not
coordinate for faults with a magnitude of 2700 Amps or
less. If the fuse is installed at a location where the
ground fault magnitude is 2900 Amps, then coordination
would exist and a breaker operation is avoided (assumes
no fault impedance). Now a 0.4 ohm NGR is added to
the circuit. The impedance at the fuse location is now
(7200/2900) + 0.4 ohms = 2.88 ohms. The fault current
has been reduced to 7200/2.88 = 2500 Amps. A
coordination problem now exists.
Approximately 99% of the fuses on CenterPoint
Energys system are 100 Amp fuses or smaller, with T
and K links being the dominant types. Assuming the
time delayed instantaneous trip and a fuse can be
coordinated with a separation of 6 cycles [14], the typical
10-cycle delay provides coordination for fault magnitudes
of 4400 Amps and greater for a 100T fuse and 3400
Amps and greater for an 80T fuse. Increasing the time
delay to 20 cycles would allow coordination to extend to
2200 Amps for a 100T and 1600 Amps for an 80T fuse.
Extending the time delay is a controversial subject within
CenterPoint Energy because of the potential for fault
duration to be damaging to the transformer. However,
with modern microprocessor relays, it is possible to
implement a stair-step time delay. Essentially, the
time delay can be changed depending on the magnitude
of the fault current. For example, a 12-cycle delay
provides coordination for fault magnitudes of 3400 Amps
and greater for a 100T. Thus, the time delay could be set
so that it would be 10 cycles for faults between 7200
Amps and 4400 Amps, 12 cycles for faults between 4400
Amps and 3400 Amps, and 20 cycles for faults below
3400 Amps. These times would allow coordination of the
breaker with a 100T fuse down to 2200 Amps, helping to
alleviate the coordination issues presented by the addition
of the NGR.
4.5. Ground Fault Protection
In addition to affecting coordination, the reduced ground
fault current magnitude also plays into how well the
substation relays will protect for a ground fault. The
relays at the substation are set so that the substation
breaker can protect for ground faults at the end of the
feeder. If the available ground fault current on the feeder
becomes too low, the relays will not be able to detect that
a ground fault has occurred and will not clear the fault.
To avoid this, either the relay settings have to be reduced
or a recloser must be installed. Since the NGR lowers the
available ground fault current, it is important to consider
if either of these actions will have to be taken.
CenterPoint Energys standard relaying practice
assumes a ground fault with an impedance of 10 ohms
when setting neutral relays. Currently, CenterPoint
Energys standard is to set the feeder neutral relays to
pickup at 480 Amps. At 12kV, this is equivalent to 5
ohms of feeder impedance: 7200/480 = 15 ohms 10
ohms for the impedance of the fault. This limits the
available single-phase fault current to 1440 Amps
(7200/5). In other words, a recloser would be called for
whenever the available ground fault current on the feeder
main is 1440 Amps or less. However, it is also possible
to reduce the neutral relay setting to protect for lower
currents as well.
The requirement to protect for ground faults at
the end of the feeder does not change with the installation
of an NGR. However, the location of a given available
ground fault current does change it moves closer to the
substation (See Figure 1). This means the relay cannot
protect as far out along a feeder as before. For example,
F ig . 1 . G ro u n d F a u l t C u r r e n t s W it h a n d W i
th o u t a n N G R f o r a n I d e n t i c a l F e e d e r
D i s t a n c e
1 2 k V S u b s ta ti o n
W i th o u t N G R
W i th 0 .4 o h m N G R
I fc = 2 9 0 0 A I fc = 2 5 0 0 A
I fc = 2 1 9 5 AI fc = 2 5 0 0 A
N o te : T h e N G R c a u s e s a g i v e n f a u lt
c u rr e n t m a g n i tu d e t o m o v e c l o s e r t o th
e
s u b s t a t io n
33
-
assume an NGR with an impedance of 0.4 ohms is
installed. As shown above, the breaker can protect for
faults along the feeder as long as the available ground
fault current is 1440 Amps or greater. This point now
occurs when the feeders own impedance is 4.6 ohms (5
ohms 0.4 ohms). The location where 1440 Amps
occurs has moved closer to the substation.
A similar analysis can be performed at 35 kV.
The effect of the NGR is negligible at this voltage because
the relay can already protect out to an available ground
fault current of 630 Amps or greater. It is extremely rare
to find an available ground fault current of this
magnitude on a feeder.
In general, the impact of the NGR is likely to be
small. It will only be of consequence at 12 kV and even
then only if the feeder is unusually long or small wire is
being used. In either of these cases, the standard
solutions of installing a recloser or lowering the neutral
relay setting can be used.
4.6. Standard Feeder Protection Scheme
Although it is not immediately obvious, the reduction in
ground fault current magnitude also impacts CenterPoint
Energys standard feeder protection scheme. In the
standard scheme, an instantaneous trip for both the phase
and neutral relays is set at 7200 Amps. While the phase
setting remains important for line to line and three phase
faults, the reduction in the available ground fault current
caused by an NGR will prevent the neutral relay from
ever seeing a fault above 7200 Amps. Thus, the
instantaneous neutral setting is no longer useful with this
setting.
As an example, consider what happens to the
ground fault current on a 12kV feeder when a 0.4 ohm
NGR is added to a 30/40/50 MVA transformer. Assume
a very high available single line to ground fault current at
the substation bus prior to installing an NGR 11,500
Amps. With the NGR, the available ground fault current
at the substation bus falls to 7020 Amps. As this example
demonstrates, even for substations at very strong busses
(high available fault currents), the NGR will reduce the
fault current below the 7200 Amp setting. Similar results
occur at 35kV.
The question arises as to whether the setting
should be revised and, if so, to what value. First,
consider the physical significance of the neutral
instantaneous setting on the feeder. At 35kV, the
distance to 7200 Amps is approximately 5200 feet while
at 12kV it is approximately 2000 feet. If we assume zero
fault impedance, then any ground fault that occurred on
this portion of the feeder would be removed as quickly as
possible. Faults on the feeder beyond this point - having
a maximum magnitude of 7199 Amps or less would be
removed only after some time delay. On the first trip,
this time delay is intentionally added to the instantaneous
trip. On all reclosing attempts, it is a function of the
time-overcurrent relay since the instantaneous element is
disabled.
If an NGR of 0.4 ohms is added to this 12KV
transformer, the available ground fault current at the
substation bus will be 7020 Amps and 5050 Amps 2000
feet out on the feeder. Ground faults that occur within
this same region of the feeder will now be removed only
after some time delay. Since the fault current magnitude
has been reduced, this may be entirely acceptable. In this
case, the relay setting can be left at 7200 Amps.
However, the setting could also be reduced to maintain
the same zone of protection out on the feeder. Here, the
setting would be lowered to 4800 Amps so that any fault
within the first 2000 feet at 12 kV and 5200 feet at 35 kV
causes an instantaneous trip. This option provides the
same level of protection for both the feeder and the
transformer that is currently in place.
Note that having one instantaneous neutral
setting for transformers with NGRs versus another for
transformers without NGRs could present a new problem.
Temporary switching could move a feeder from a
substation transformer with an NGR to one without an
NGR. The lowered instantaneous neutral setting will
cause the feeder to experience more circuit operations
from faults behind fuses. This problem could be avoided
if all the transformers at a given secondary voltage had an
NGR installed. Thus, under this option, it appears that
the neutral instantaneous setting should remain
unchanged until all transformers at 12kV or 35kV at a
substation have NGRs added to them. Once this occurs,
concerns about temporary switching would no longer
exist and the setting could be reduced to further protect
the transformer.
CenterPoint Energy has decided to standardize
on the lowered neutral instantaneous setting for feeders
served from transformers with NGRs. This change will
be implemented only after all transformers with the same
secondary voltage at a substation have NGRs installed.
5. WESTFIELD PROJECT
CenterPoint Energy has been conducting a pilot project
for NGRs at its Westfield substation for approximately 8
years. NGRs were installed at each of the four
transformers at Westfield. Two of these transformers are
132kV 12.47kV, delta wye grounded, 25/33/42/47
MVA units while the other two are 138kV 34.5 kV,
delta wye grounded, 50/60/83/93 MVA units. All
transformers are served at 138kV, with the 12.47kV units
tapped to 138kV on the high side. The NGRs installed
on the 12kV transformers were set at 0.4 ohms of
34
-
impedance while those on the 35kV transformers were set
at 1.4 ohms of impedance. This impedance provides the
maximum reduction possible while still maintaining an
effectively grounded system.
In 2001, monitors were installed along two
distribution feeders to record the TOVs experienced
during ground faults. The goal of the monitoring project
was to validate the expected maximum TOV results
modeled by CenterPoint Energy. However, the project
also helped to address the issue of voltage regulation.
Data was collected from July 2001 through August 2003.
5.1. Monitoring Project Setup
The two feeders selected for the project were Westfield 41
and Westfield 02 - a 35kV and a 12kV feeder. Four
monitors were deployed along each feeder. The monitors
were installed on the low side of a customers distribution
transformer at each of the selected locations, either
directly on the secondary conductors or at the meter.
Originally, a combination of monitors was used
Five Telog Linecorder (LC) 800, one Power Monitors
Incorporated (PMI) VI/600 and two PMI VS-1S. The
Telog LC 800 and the PMI VI/600 record three phase
voltages and currents; the PMI VS-1S records single-
phase voltages and currents. During the project, the
Telog units failed frequently, producing gaps in the data.
All the Telog units were replaced with PMI IV/600s after
April 2002.
On 35kV circuits, the most common transformer
connection for a three-phase customer is grounded wye-
grounded wye. This type of connection was preferable for
the project since the voltages measured line to neutral on
the customers side of the transformer are analogous to
the line to neutral voltages on the feeder. On Westfield
41, all four of the monitoring locations used this
connection.
On 12kV circuits, different types of transformer
connections are common. This proved to be a challenge
as suitable grounded wye - grounded wye locations could
not be found on Westfield 02. Instead, an alternate
method of getting analogous readings to the feeder line to
neutral voltages was found. Two customer locations were
combined to cover all three phases. One location was
served by an open wye-open delta transformer bank; the
other by a single-phase transformer. All three of the
transformers were served line to neutral on the high side
from different phases. In the case of the open wye-open
delta bank, reading the low side line to line voltages
provides analogous readings to the high side line to
neutral readings. Low side AB is analogous to high side
AN and low side BC is analogous to high side BN. Low
side CA is the ghost phase the vector sum of low side
AB and BC and is analogous to the vector sum of high
side AN and BN. This two-customer combination was
used twice to provide two different points on the feeder
where all three voltages could be recorded.
Both feeders serve predominantly residential and
commercial customers, with some light industrial. The
12kV feeder is 4.1 miles long. The two monitoring
locations were 1.25 and 2.5 miles from the substation.
The 35kV feeder is 4.6 miles long. After 1.8 miles, the
feeder branches into two parts that each having about the
same length. The four monitoring locations for this
feeder were located 1.3, 2.4, 3.4, and 3.5 miles from the
substation. The last two locations on the 35kV feeder
were on different branches. All distances are calculated
by following the path of the actual conductor.
5.2. Results
The data in the following figures represent the recorded
voltage events. A voltage event was defined as a change
in voltage of +/-10% of the nominal secondary voltage at
that location. Only one location had to report a +/-10%
change in voltage for the event to be listed the same
event may not have caused as great a rise or dip at the
other monitored locations. Where possible, events were
confirmed as being seen at other locations before being
included in this list. If the other monitors did not record
a voltage change, then the event was considered
unconfirmed and not included. However, in a few
instances, only one monitor was operating. These events
are included in the figures.
020406080
100120140160180200220240
L-G L-L 2L-G L-L-L All
Fault Type
No
. o
f F
ault
s
Fig. 2 Distribution of Recorded Fault Types
Figure 2 shows the types of fault recorded by the
monitors. The results of both the 12kV and 35kV feeders
are shown combined. Line to ground faults account for
58% of all faults while line to line faults account for 32%.
35
-
The unusually high number of line to line faults occurred
due to faults on the transmission system. Because the
power transformers are connected delta on the high side,
line to ground faults on the transmission system appear as
line to line faults on the secondary side. When
transmission faults are eliminated, the breakdown of fault
types generally matches the expected distribution. Figure
3 shows the distribution with transmission system faults
eliminated. In Figure 3, the breakdown of faults is 71%
single line to ground and 17% line to line.
020
406080
100
120140160
180200
L-G L-L 2L-G L-L-L All
Fault Type
No
. o
f F
ault
s
Fig. 3 Distribution of Recorded Fault Types, Excluding
Transmission Events
Single line to ground faults are generally
expected to account for 70% of all faults while line to line
faults are generally expected to account for 15% of all
faults [10]. Note that seventeen of the faults recorded
changed type before being cleared. Their initial fault type
categorizes these faults.
0
2
4
6
8
10
12
14
16
1.30
Maximum TOV in p u of No minal Seco ndary Vo ltage
(12 kV Event s )
No. o
f E
ven
ts
Fig. 4 Distribution of Maximum TOVs Recorded for the
12kV Feeder
0
5
10
15
20
25
30
35
40
1.30
M aximum TOV in pu o f No minal Sec o nda ry Vo ltage
(35kV Events )
No
. o
f ev
ents
Fig. 5 Distribution of Maximum TOVs Recorded for the
35kV Feeder
Figures 4 and 5 show the highest TOV recorded on any
phase by any of the monitors for each event on the 12kV
and the 35kV feeders, respectively. The TOV in both
figures is expressed in per unit of nominal secondary
voltage. There were a total of 35 events on the 12kV
feeder and 101 events on the 35kV feeder recorded. The
35kV feeder results include one event associated with a
transmission fault while the 12kV events do not include
one line to ground fault for which no TOV was recorded.
Of the 136 events, approximately 15% caused a TOV of
1.20pu or greater at one of the monitoring locations. The
highest recorded TOVs were 1.26pu on the 35kV feeder
and 1.24pu on 12kV feeder.
It is important to note that it would be virtually
impossible to record the maximum TOV that can occur
on a feeder. For any given fault, the maximum TOV
occurs at the fault location. This maximum TOV value
will vary depending on the point along the feeder where
the fault occurs. Thus, directly determining the
maximum TOV capable of being experienced on the
feeder would require installing a monitor at and applying
a fault to every point on the feeder. Clearly, this is not
practical.
Instead, the project sought to gather indirect
evidence. The largest TOV recorded at any location
would indicate that the maximum TOV was this value or
greater. The more faults recorded by the monitors, the
more likely that the maximum value recorded would be
closer to the actual maximum value. In addition, one can
form an opinion as to the frequency and magnitude of the
voltage events seen on these feeders. Since the recorded
TOV values are substantially below the predicted value of
1.35pu, the authors believe it is very likely that the
1.35pu value represents a reasonable upper limit for the
TOV.
36
-
02468
101214
0 - 3 3.0 1 -
6
6.01 -
9
9 .01 -
11
11.0 1
- 15
15.01
- 20
2 0.0 1
- 25
2 5.01
- 3 0
30 .01
- 4 0
4 0.0 1
- 50
>50
Line to Ground Fault Duration in Cycles
(12kV Events)
No
. o
f E
ve
nts
Fig. 6 Distribution of Line to Ground Fault Durations
for the 12kV Feeder
010
2030405060
0 - 3 3.0 1 -
6
6.01 -
9
9 .01 -
11
11.0 1
- 15
15.01
- 20
2 0.0 1
- 25
2 5.01
- 3 0
30 .01
- 4 0
4 0.0 1
- 50
>50
Line to Ground Fault Duration in Cycles
(35kV Feeder)
No
. o
f E
ve
nts
Fig. 7 Distribution of Line to Ground Fault Durations
for the 35kV Feeder
Figures 6 and 7 show the duration of the 12kV
and 35kV line to ground events, respectively. The data in
these figures excludes 12 events at 35kV and 2 events at
12kV in which fault duration did not get recorded. It also
excludes 14 events at 35kV and 2 events at 12kV that
changed fault type before the fault was cleared. As
previously mentioned, a separate study by CenterPoint
Energy showed that at both 12kV and 35kV,
approximately 70% of all faults last less than 3 cycles and
approximately 17% of all faults last more than 11 cycles.
This includes all fault types; however, since line to
ground faults account for the majority of the data, a valid
comparison can be made. At 12kV, fault duration was
noticeably longer than would typically be expected while
at 35kV the results were in line with the expected data.
Only 42% of the events on the 12kV feeder lasted 3
cycles or less while 25% lasted longer than 11 cycles. On
the 35kV feeder, 73% of the events lasted 3 cycles or less
and 14% lasted 11 cycles or more. This suggests the
NGRs impedance does not significantly increase fault
duration at 35kV, but does at 12kV. It is unclear to the
authors why such a difference would exist.
Although not originally a purpose of the
monitoring project, voltage regulation data was collected
by each of the monitors. This data was reviewed to see if
a voltage regulation problem had occurred on the feeders.
Each monitor recorded an average voltage for a user-
defined period of time. This was generally set as 1
minute, but other times were inadvertently used as well
and are noted in the tables. For each data point, the
phase with the highest or lowest average voltage was
compared to +/-5% of the nominal secondary voltage.
These limits were chosen based on the Range A limits in
ANSI C84.1 Voltage Ratings for Electric Power Systems
and Equipment (60Hz) [15]. CenterPoint Energy is
required to provide its customers service in accordance
with this standard.
Table I shows the data for the 35kV feeder and
Table II shows the data for the 12kV feeder. Although
efforts were made to keep all monitors operating
simultaneously, this wasnt always possible. Thus, the
total number of minutes is different for each monitor.
In Table I, it is clear that the average voltage
rarely moved above or below +/-5% of nominal voltage.
The results are consistent with providing service in
accordance with the standard - no regulation problems
occurred. The 156 minutes of high voltage recorded at
Location B all occurred on two days, with the highest
average voltage reaching 107% of nominal voltage.
Voltage on all three phases was near the 105% voltage
limit. Since all the phases moved together, this was not
the result of installing the NGR.
37
-
In Table II, Location E and G are the open delta
transformer banks and Locations F and H are the single-
phase transformer banks. Location E and F combined
give all three phases and Locations G and H combined
give all three phases. Note that the single-phase monitors
are on different phases.
Of the 857 low voltage data points occurring at
Location E, 823 of them occurred because of a bad
connection at this transformer bank. Excluding these
points, the results for Locations E and F show no voltage
regulation problems. Location G recorded by far the most
data points outside the limits. These data points occurred
almost exclusively during the summer months and are
attributable to an overloaded transformer bank. Although
this does indicate a voltage regulation problem, it is not
from the NGR. Overall, the results show no voltage
regulation problem associated with the NGR.
6. CONCLUSION
The primary driver for installing an NGR is its beneficial
effect on transformer life expectancy. Most transformer
failures at CenterPoint Energy are attributed to the stress
placed on the windings by faults on the distribution
system. By lowering the magnitude of single line to
ground faults, which make up 70% of all faults, the NGR
can greatly diminish these stresses. The transformers
short circuit strength its ability to withstand the forces
associated with carrying fault current need not be as
high to prevent an internal failure. Furthermore, the
reduction in ground fault current magnitude slows the
erosion of the transformers short circuit strength. For
these reasons, the NGR is an attractive method for
addressing the most common type of transformer failure.
The increase in the system ground impedance
caused by an NGR also affects the distribution system.
The NGRs impedance increases the neutral shift that
results from unbalanced loading or ground fault currents.
In addition, it affects protective device coordination,
ground fault protection, and the standard feeder
protection scheme by reducing the magnitude of ground
faults. However, the NGRs impact on each of these
areas is generally small and manageable.
The Westfield Project strongly suggests that
voltage regulation is not significantly impacted by the
NGR. It also provides support for the modeled maximum
TOV value of 1.35pu a value that should be acceptable
for both the lightning arrestors on the system and
customer owned equipment. Breaker/recloser to fuse
coordination problems can be handled by using a stair-
step approach to the time delay of the instantaneous
element. Ground protection settings may need to be
lowered slightly, if required to protect the end of the
feeder. It is true that some aspects of power quality
such as the deepening and lengthening of voltage sags
will worsen. Whether this represents a practical problem
for customers will depend largely on the type of
equipment the customer owns. The authors of this paper
believe it will not.
7. ACKNOWLEDGEMENTS
The authors of this report wish to acknowledge the many
individuals who contributed to this report. The High
Voltage Metering Meter Functions group helped select,
install, maintain, and download all of the monitoring
devices installed on the Westfield project. M. Khayat of
CenterPoint Energy helped build the model used to
estimate the maximum TOV for 12 kV and 35 kV
feeders.
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39
