Voltage sags are short duration reductions in rms voltage, mainly caused
by short circuits and starting of large motors. The interest in voltage sags
is due to the problems they cause on several types of equipment.
Adjustablespeed drives, processcontrol equipment, and computers are especially
notorious for their sensitivity. Some pieces of equipment trip when the rms
voltage drops below 90% for longer than one or two cycles. Such a piece of
equipment will trip tens of times a year. If this is the processcontrol equipment
of a paper mill, one can imagine that the costs due to voltage sags can be
enormous. A voltage sag is not as damaging to industry as a (long or short)
interruption, but as there are far more voltage sags than interruptions, the
total damage due to sags is still larger. Another important aspect of voltage
sags is that they are hard to mitigate. Short interruptions and many long interruptions
can be prevented via simple, although expensive measures in the local distribution
network. Voltage sags at equipment terminals can be due to shortcircuit faults
hundreds of kilo meters away in the transmission system. It will be clear that
there is no simple method to prevent them.
1. Voltage Sag Characteristics
An example of a voltage sag is shown in FIG. 1. The voltage amplitude drops
to a value of about 20% of its preevent value for about two and a half cycles,
after which the voltage recovers again. The event shown in FIG. 1 can be characterized
as a voltage sag down to 20% (of the preevent voltage) for 2.5 cycles (of
the fundamental frequency). This event can be characterized as a voltage sag
with a magnitude of 20% and a duration of 2.5 cycles.
FIG. 1 A voltage sagvoltage in one phase in time domain.
1.1 Voltage Sag Magnitude: Monitoring
The magnitude of a voltage sag is determined from the rms voltage. The rms
voltage for the sag in FIG. 1 is shown in FIG. 2. The rms voltage has been
calculated over a onecycle sliding window:
(eqn 1)
with N the number of samples per cycle, and v(i) the sampled voltage in time
domain. The rms voltage as shown in FIG. 2 does not immediately drop to a lower
value, but takes one cycle for the transition. This is due to the finite length
of the window used to calculate the rms value. We also see that the rms value
during the sag is not completely constant and that the voltage does not immediately
recover after the fault.
FIG. 2 Onecycle rms voltage for the voltage sag shown in FIG. 1.
There are various ways of obtaining the sag magnitude from the rms voltages.
Most power quality monitors take the lowest value obtained during the event.
As sags normally have a constant rms value during the deep part of the sag,
using the lowest value is an acceptable approximation.
The sag is characterized through the remaining voltage during the event. This
is then given as a percentage of the nominal voltage. Thus, a 70% sag in a
230V system means that the voltage dropped to 161 V. The confusion with this
terminology is clear. One could be tricked into thinking that a 70% sag refers
to a drop of 70%, thus a remaining voltage of 30%. The recommendation is therefore
to use the phrase "a sag down to 70%." Characterizing the sag through
the actual drop in rms voltage can solve this ambiguity, but this will introduce
new ambiguities like the choice of the reference voltage.
1.2 Origin of Voltage Sags
Consider the distribution network shown in FIG. 3, where the numbers (1 through
5) indicate fault positions and the letters (A through D) loads. A fault in
the transmission network, fault position 1, will cause a serious sag for both
substations bordering the faulted line. This sag is transferred down to all
customers fed from these two substations. As there is normally no generation
connected at lower voltage levels, there is nothing to keep up the voltage.
The result is that all customers (A, B, C, and D) experience a deep sag. The
sag experienced by A is likely to be somewhat less deep, as the generators
connected to that substation will keep up the voltage. A fault at position
2 will not cause much voltage drop for customer A. The impedance of the transformers
between the transmission and the subtransmission system are large enough to
considerably limit the voltage drop at highvoltage side of the transformer.
The sag experienced by customer A is further mitigated by the generators feeding
into its local transmission substation. The fault at position 2 will, however,
cause a deep sag at both subtransmission substations and thus for all customers
fed from here (B, C, and D). A fault at position 3 will cause a short or long
interruption for customer D when the protection clears the fault. Customer
C will only experience a deep sag. Customer B will experience a shallow sag
due to the fault at position 3, again due to the transformer impedance. Customer
A will probably not notice anything from this fault. Fault 4 causes a deep
sag for customer C and a shallow one for customer D. For fault 5, the result
is the other way around: a deep sag for customer D and a shallow one for customer
C. Customers A and B will not experience any significant drop in voltage due
to faults 4 and 5.
FIG. 3 Distribution network with load positions (A through D) and fault positions
(1 through 5).
FIG. 4 Voltage divider model for a voltage sag.
1.3 Voltage Sag Magnitude: Calculation
To quantify sag magnitude in radial systems, the voltage divider model, shown
in FIG. 4, can be used, where Z is the source impedance at the pointofcommon
coupling; and Z is the impedance between the pointofcommon coupling and the
fault. The pointofcommon coupling (pcc) is the point from which both the
fault and the load are fed. In other words, it is the place where the load
current branches off from the fault current. In the voltage divider model,
the load current before, as well as during the fault is neglected. The voltage
at the pcc is found from
(eqn 2)
where it is assumed that the preevent voltage is exactly 1 pu, thus E = 1.
The same expression can be derived for constantimpedance load, where E is
the preevent voltage at the pcc. We see from Equation 2 that the sag becomes
deeper for faults electrically closer to the customer (when ZF becomes smaller),
and for weaker systems (when ZS becomes larger).
FIG. 5 Sag magnitude as a function of the distance to the fault.
Equation 2 can be used to calculate the sag magnitude as a function of the
distance to the fault.
Therefore, we write ZF = zd, with z the impedance of the feeder per unit length
and d the distance between the fault and the pcc, leading to
(eqn 3)
This expression has been used to calculate the sag magnitude as a function
of the distance to the fault for a typical 11 kV overhead line, resulting in
FIG. 5. For the calculations, a 150mm2 overhead line was used and fault levels
of 750, 200, and 75 MVA. The fault level is used to calculate the source impedance
at the pcc and the feeder impedance is used to calculate the impedance between
the pcc and the fault. It is assumed that the source impedance is purely reactive,
thus ZS = j 0.161 ohm for the 750 MVA source. The impedance of the
150 mm2 overhead line is z = 0.117 + j 0.315 ohm/km.
1.4 Propagation of Voltage Sags
It is also possible to calculate the sag magnitude directly from fault levels
at the pcc and at the fault position. Let SFLT be the fault level at the fault
position and SPCC at the pointofcommon coupling. The voltage at the pcc can
be written as
(eqn 4)
This equation can be used to calculate the magnitude of sags due to faults
at voltage levels other than the pointofcommon coupling. Consider typical
fault levels as shown in Table 1. This data has been used to obtain Table 2,
showing the effect of a short circuit fault at a lower voltage level than the
pcc.
We can see that sags are significantly "damped" when they propagate
upwards in the power system. In a sags study, we typically only have to take
faults one voltage level down from the pcc into account. And even those are
seldom of serious concern. Note, however, that faults at a lower voltage level
may be associated with a longer faultclearing time and thus a longer sag duration.
This especially holds for faults on distribution feeders, where faultclearing
times in excess of 1 s are possible.
1.5 Critical Distance
Equation 3 gives the voltage as a function of distance to the fault. From
this equation we can obtain the distance at which a fault will lead to a sag
of a certain magnitude V. If we assume equal X/R ratio of source and feeder,
we get the following equation:
(eqn 5)
TABLE 1 Typical Fault Levels at Different Voltage Levels
TABLE 2 Propagation of Voltage Sags to Higher Voltage Levels
TABLE 3 Critical Distance for Faults at Different Voltage Levels
We refer to this distance as the critical distance. Suppose that a piece of
equipment trips when the volt age drops below a certain level (the critical
voltage). The definition of critical distance is such that each fault within
the critical distance will cause the equipment to trip. This concept can be
used to estimate the expected number of equipment trips due to voltage sags.
The critical distance has been calculated for different voltage levels, using
typical fault levels and feeder impedances. The data used and the results obtained
are summarized in Table 3 for the critical voltage of 50%. Note how the critical
distance increases for higher voltage levels. A customer will be exposed to
much more kilometers of transmission lines than of distribution feeder. This
effect is understood by writing Equation 5 as a function of the shortcircuit
current Iflt at the pcc:
(eqn 6)
with Vnom the nominal voltage. As both z and Iflt are of similar magnitude
for different voltage levels, one can conclude from Equation 6 that the critical
distance increases proportionally with the voltage level.
1.6 Voltage Sag Duration
It was shown before, the drop in voltage during a sag is due to a short circuit
being present in the system.
The moment the short circuit fault is cleared by the protection, the voltage
starts to return to its original value. The duration of a sag is thus determined
by the faultclearing time. However, the actual duration of a sag is normally
longer than the faultclearing time.
Measurement of sag duration is less trivial than it might appear. From a recording
the sag duration may be obvious, but to come up with an automatic way for a
power quality monitor to obtain the sag duration is no longer straightforward.
The commonly used definition of sag duration is the number of cycles during
which the rms voltage is below a given threshold. This threshold will be somewhat
different for each monitor but typical values are around 90% of the nominal
voltage. A power quality monitor will typically calculate the rms value once
every cycle.
The main problem is that the socalled postfault sag will affect the sag
duration. When the fault is cleared, the voltage does not recover immediately.
This is mainly due to the reenergizing and reacceleration of induction motor
load. This postfault sag can last several seconds, much longer than the actual
sag. Therefore, the sag duration as defined before, is no longer equal to the
fault clearing time. More seriously, different power quality monitors will
give different values for the sag duration. As the rms voltage recovers slowly,
a small difference in threshold setting may already lead to a serious difference
in recorded sag duration.
Generally speaking, faults in transmission systems are cleared faster than
faults in distribution systems. In transmission systems, the critical faultclearing
time is rather small. Thus, fast protection and fast circuit breakers are essential.
Also, transmission and subtransmission systems are normally operated as a grid,
requiring distance protection or differential protection, both of which allow
for fast clearing of the fault. The principal form of protection in distribution
systems is overcurrent protection. This requires a certain amount of timegrading,
which increases the faultclearing time. An exception is formed by systems
in which currentlimiting fuses are used. These have the ability to clear a
fault within one halfcycle. In overhead distribution systems, the instantaneous
trip of the recloser will lead to a short sag duration, but the clearing of
a permanent fault will give a sag of much longer duration.
The socalled magnitudeduration plot is a common tool used to show the quality
of supply at a certain location or the average quality of supply of a number
of locations. Voltage sags due to faults can be shown in such a plot, as well
as sags due to motor starting, and even long and short interruptions. Different
underlying causes lead to events in different parts of the magnitudeduration
plot, as shown in FIG. 6.
FIG. 6 Sags of different origin in a magnitudeduration plot.
1.7 PhaseAngle Jumps
A short circuit in a power system not only causes a drop in voltage magnitude,
but also a change in the phase angle of the voltage. This sudden change in
phase angle is called a "phaseangle jump." The phaseangle jump
is visible in a timedomain plot of the sag as a shift in voltage zerocrossing
between the preevent and the duringevent voltage. With reference to FIG.
4 and Equation 2, the phase angle jump is the argument of Vsag, thus the difference
in argument between ZF and ZS + ZF. If source and feeder impedance have equal
X/R ratio, there will be no phaseangle jump in the voltage at the pcc.
This is the case for faults in transmission systems, but normally not for
faults in distribution systems.
The latter may have phaseangle jumps up to a few tens of degrees.
FIG. 4 shows a singlephase circuit, which is a valid model for threephase
faults in a threephase system. For nonsymmetrical faults, the analysis becomes
much more complicated. A consequence of nonsymmetrical faults (singlephase,
phasetophase, twophasetoground) is that singlephase load experiences
a phaseangle jump even for equal X/R ratio of feeder and source impedance.
To obtain the phaseangle jump from the measured voltage waveshape, the phase
angle of the voltage during the event must be compared with the phase angle
of the voltage before the event. The phase angle of the voltage can be obtained
from the voltage zerocrossings or from the argument of the fundamental component
of the voltage. The fundamental component can be obtained by using a discrete
Fourier trans form algorithm. Let V1(t) be the fundamental component obtained
from a window (tT,t), with T one cycle of the power frequency, and let t =
0 correspond to the moment of sag initiation. In case there is no chance in
voltage magnitude or phase angle, the fundamental component as a function of
time is found from
(eqn. 7)
The phaseangle jump, as a function of time, is the difference in phase angle
between the actual fundamental component and the "synchronous voltage" according
to Equation 7:
(eqn 8)
Note that the argument of the latter expression is always between 180° and
+180°.
1.8 ThreePhase Unbalance
For threephase equipment, three voltages need to be considered when analyzing
a voltage sag event at the equipment terminals. For this, a characterization
of threephase unbalanced voltage sags is introduced. The basis of this characterization
is the theory of symmetrical components. Instead of the three phase voltages
or the three symmetrical components, the following three (complex) values are
used to characterize the voltage sag:
• The "characteristic voltage" is the main characteristic of the
event. It indicates the severity of the sag, and can be treated in the same
way as the remaining voltage for a sag experienced by a single phase event.
• The "PN factor" is a correction factor for the effect of the load
on the voltages during the event.
The PN factor is normally close to unity and can then be neglected. Exceptions
are systems with a large amount of dynamic load, and sags due to twophasetoground
faults.
• The "zerosequence voltage," which is normally not transferred
to the equipment terminals, rarely affects equipment behavior. The zerosequence
voltage can be neglected in most studies.
Neglecting the zerosequence voltage, it can be shown that there are two types
of threephase unbalanced sags, denoted as types C and D. Type A is a balanced
sag due to a threephase fault. Type B is the sag due to a singlephase fault,
which turns into type D after removal of the zerosequence voltage. The three
complex voltages for a type C sag are written as follows:
(eqn 9)
...where V is the characteristic voltage and F the PN factor. The (characteristic)
sag magnitude is defined as the absolute value of the characteristic voltage;
the (characteristic) phaseangle jump is the argument of the characteristic
voltage. For a sag of type D, the expressions for the three voltage phasors
are as follows:
(eqn 10)
Sag type D is due to a phasetophase fault, or due to a singlephase fault
behind a [delta]ytransformer, or a phasetophase fault behind two [delta]ytransformers,
etc. Sag type C is due to a singlephase fault, or due to a phasetophase
fault behind a [delta]ytransformer, etc. When using characteristic voltage
for a three phase unbalanced sag, the same singlephase scheme as in FIG. 4
can be used to study the transfer of voltage sags in the system.
2. Equipment Voltage Tolerance
2.1 Voltage Tolerance Requirement
Generally speaking, electrical equipment prefers a constant rms voltage. That
is what the equipment has been designed for and that is where it will operate
best. The other extreme is zero voltage for a longer period of time. In that
case the equipment will simply stop operating completely. For each piece of
equipment there is a maximum interruption duration, after which it will continue
to operate correctly. A rather simple test will give this duration. The same
test can be done for a voltage of 10% (of nominal), for a voltage of 20%, etc.
If the voltage becomes high enough, the equipment will be able to operate on
it indefinitely. Connecting the points obtained by performing these tests results
in the socalled "voltagetolerance curve". An example
of a voltagetolerance curve is shown in FIG. 7: the requirements for ITequipment
as recommended by the Information Technology Industry Council (ITIC). Strictly
speaking, one can claim that this is not a voltagetolerance curve as described
above, but a requirement for the voltage tolerance. One could refer to this
as a voltagetolerance requirement and to the result of equipment tests as
a voltagetolerance performance.
We see in FIG. 7 that IT equipment has to withstand a voltage sag down to
zero for 1.1 cycle, down to 70% for 30 cycles, and that the equipment should
be able to operate normally for any voltage of 90% or higher.
2.2 Voltage Tolerance Performance
Voltagetolerance (performance) curves for personal computers are shown in
FIG. 8. The curves are the result of equipment tests performed in the United
States and in Japan. The shape of all the curves in FIG. 8 is close to rectangular.
This is typical for many types of equipment, so that the voltage tolerance
may be given by only two values, maximum duration and minimum voltage, instead
of by a full curve. From the tests summarized in FIG. 8 it is found that the
voltage tolerance of personal computers varies over a wide range: 30170 ms,
50%70% being the range containing half of the models. The extreme values found
are 8 ms, 88% and 210 ms, 30%.
Voltagetolerance tests have also been performed on processcontrol equipment:
PLCs, monitoring relays, motor contactors. This equipment is even more sensitive
to voltage sags than personal computers. The majority of devices tested tripped
between one and three cycles. A small minority was able to tolerate sags up
to 15 cycles in duration. The minimum voltage varies over a wider range: from
50% to 80% for most devices, with exceptions of 20% and 30%. Unfortunately,
the latter two both tripped in three cycles.
FIG. 7 Voltagetolerance requirement for IT equipment.
FIG. 8 Voltagetolerance performance for personal computers.
FIG. 9 Average voltagetolerance curve for adjustablespeed drives.
From performance testing of adjustablespeed drives, an "average voltagetolerance
curve" has been obtained. This curve is shown in FIG. 9. The sags for
which the drive was tested are indicated as circles. It has further been assumed
that the drives can operate indefinitely on 85% voltage. Voltage tolerance
is defined here as "automatic speed recovery, without reaching zero speed." For
sensitive production processes, more strict requirements will hold.
2.3 SinglePhase Rectifiers
The sensitivity of most singlephase equipment can be understood from the
equivalent scheme in FIG. 10. The power supply to a computer, processcontrol
equipment, consumer electronics, etc. consists of a singlephase (fourpulse)
rectifier together with a capacitor and a DC/DC converter. During nor mal operation
the capacitor is charged twice a cycle through the diodes. The result is a
DC voltage ripple:
(eqn 11)
... with P the DC bus activepower load, T one cycle of the power frequency, V0
the maximum DC bus volt age, and C the size of the capacitor.
FIG. 10 Typical power supply to sensitive singlephase equipment.
FIG. 11 Absolute value of AC voltage (dashed) and DC bus voltage (solid line)
for a sag down to 50%.
During a voltage sag or interruption, the capacitor continues to discharge
until the DC bus volt age has dropped below the peak of the supply voltage.
A new steady state is reached, but at a lower DC bus voltage and with a larger
ripple. The resulting DC bus voltage for a sag down to 50% is shown in FIG.
11, together with the absolute value of the supply voltage. If the new steady
state is below the minimum operating voltage of the DC/DC converter, or below
a certain protection setting, the equipment will trip. During the decaying
DC bus voltage, the capacitor voltage V(t) can be obtained from the law of
conservation of energy:
(eqn 12)
where a constant DC bus load P has been assumed. From Equation 12 the voltage
as a function of time is obtained:
(eqn 13)
Combining this with Equation 11 gives the following expression:
(eqn 14)
The larger the DC ripple in normal operation, the faster the drop in DC bus
voltage during a sag. From Equation 14 the maximum duration of zero voltage
tmax is calculated for a minimum operating volt age Vmin, resulting in
(eqn 15)
2.4 ThreePhase Rectifiers
The performance of equipment fed through threephase rectifiers becomes somewhat
more complicated. The main equipment belonging to this category is formed by
AC and DC adjustablespeed drives.
One of the complications is that the operation of the equipment is affected
by the three voltages, which are not necessarily the same during the voltage
sag. For noncontrolled (six pulse) diode rectifiers, a similar model can be
used as for singlephase rectifiers. The operation of threephase controlled
rectifiers can become very complicated and applicationspecific. Therefore,
only noncontrolled rectifiers will be discussed here. For voltage sags due
to threephase faults, the DC bus voltage behind the (threephase) rectifier
will decay until a new steady state is reached at a lower voltage level, with
a larger ripple. To calculate the DC bus voltage as a function of time, and
the timetotrip, the same equation as for the singlephase rectifier can be
used.
FIG. 12 AC and DC side voltages for a threephase rectifier during a sag of
type C.
FIG. 13 AC and DC side voltages for a threephase rectifier during a sag of
type D.
For unbalanced voltage sags, a distinction needs to be made between the two
types (C and D), as introduced in Section 38.1.8. FIG. 12 shows AC and DC side
voltages for a sag of type C with V = 0.5 pu and F = 1. For this sag, the voltage
drops in two phases where the third phase stays at its presage value. Three
capacitor sizes are used; a "large" capacitance is defined as a value
that leads to an initial decay of the DC voltage equal to 10%, which is 433
F/kW for a 620 V drive. In the same way, "small" capacitance corresponds
to 75% per cycle initial decay, and 57.8 F/kW for a 620 V drive. It turns out
that even for the small capacitance, the DC bus voltage remains above 70%.
For the large capacitance value, the DC bus voltage is hardly affected by the
voltage sag. It is easy to understand that this is also the case for type C
sags with an even lower characteristic magnitude V.
FIG. 13 shows the equivalent results for a sag of type D, again with V = 0.5
and F = 1. As all three AC voltages show a drop in voltage magnitude, the DC
bus voltage will drop even for a large capacitor.
But the effect is still much less than for a threephase (balanced) sag.
The effect of a lower PN factor (F < 1) is that even the highest voltage
shows a drop for a type C sag, so that the DC bus voltage will always show
a small drop. Also for a type D sag, a lower PN factor will lead to an additional
drop in DC bus voltage.
3. Mitigation of Voltage Sags
3.1 From Fault to Trip
To understand the various ways of mitigation, the mechanism leading to an
equipment trip needs to be understood. The equipment trip is what makes the
event a problem; if there are no equipment trips, there is no voltage sag problem.
The underlying event of the equipment trip is a shortcircuit fault. At the
fault position, the voltage drops to zero, or to a very low value. This zero
voltage is changed into an event of a certain magnitude and duration at the
interface between the equipment and the power system. The shortcircuit fault
will always cause a voltage sag for some customers. If the fault takes place
in a radial part of the system, the protection intervention clearing the fault
will also lead to an interruption. If there is sufficient redundancy present,
the short circuit will only lead to a voltage sag. If the resulting event exceeds
a certain severity, it will cause an equipment trip.
Based on this reasoning, it is possible to distinguish between the following
mitigation methods:
• Reducing the number of shortcircuit faults.
• Reducing the faultclearing time.
• Changing the system such that shortcircuit faults result in less severe
events at the equipment terminals or at the customer interface.
• Connecting mitigation equipment between the sensitive equipment and the
supply.
• Improving the immunity of the equipment.
3.2 Reducing the Number of Faults
Reducing the number of shortcircuit faults in a system not only reduces the
sag frequency, but also the frequency of long interruptions. This is thus a
very effective way of improving the quality of supply and many customers suggest
this as the obvious solution when a voltage sag or interruption problem occurs.
Unfortunately, most of the time the solution is not that obvious. A short circuit
not only leads to a voltage sag or interruption at the customer interface,
but may also cause damage to utility equipment and plant. Therefore, most utilities
will already have reduced the fault frequency as far as economically feasible.
In individual cases, there could still be room for improvement, e.g., when
the majority of trips are due to faults on one or two distribution lines. Some
examples of fault mitigation are:
• Replace overhead lines by underground cables.
• Use special wires for overhead lines.
• Implement a strict policy of tree trimming.
• Install additional shielding wires.
• Increase maintenance and inspection frequencies.
One has to keep in mind, however, that these measures can be very expensive,
especially for transmission systems, and that their costs have to be weighted
against the consequences of the equipment trips.
3.3 Reducing the FaultClearing Time
Reducing the faultclearing time does not reduce the number of events, but
only their severity. It does not do anything to reduce to number of interruptions,
but can significantly limit the sag duration. The ultimate reduction of faultclearing
time is achieved by using currentlimiting fuses, able to clear a fault within
one halfcycle. The recently introduced static circuit breaker has the same
characteristics: faultclearing time within one halfcycle. Additionally, several
types of faultcurrent limiters have been proposed that do not actually clear
the fault, but significantly reduce the fault current magnitude within one
or two cycles. One important restriction of all these devices is that they
can only be used for low and mediumvoltage systems. The maximum operating
voltage is a few tens of kilovolts.
But the faultclearing time is not only the time needed to open the breaker,
but also the time needed for the protection to make a decision. To achieve
a serious reduction in faultclearing time, it is necessary to reduce any grading
margins, thereby possibly allowing for a certain loss of selectivity.
3.4 Changing the Power System
By implementing changes in the supply system, the severity of the event can
be reduced. Here again, the costs may become very high, especially for transmission
and subtransmission voltage levels. In industrial systems, such improvements
more often outweigh the costs, especially when already included in the design
stage. Some examples of mitigation methods especially directed toward voltage
sags are
• Install a generator near the sensitive load. The generators will keep up
the voltage during a remote sag. The reduction in voltage drop is equal to
the percentage contribution of the generator station to the fault current.
In case a combinedheatandpower station is planned, it is worth it to consider
the position of its electrical connection to the supply.
• Split buses or substations in the supply path to limit the number of feeders
in the exposed area.
• Install currentlimiting coils at strategic places in the system to increase
the "electrical distance" to the fault. The drawback of this method
is that this may make the event worse for other customers.
• Feed the bus with the sensitive equipment from two or more substations.
A voltage sag in one substation will be mitigated by the infeed from the other
substations. The more independent the substations are, the more the mitigation
effect. The best mitigation effect is by feeding from two different transmission
substations. Introducing the second infeed increases the number of sags, but
reduces their severity.
3.5 Installing Mitigation Equipment
The most commonly applied method of mitigation is the installation of additional
equipment at the systemequipment interface. Also recent developments point
toward a continued interest in this way of mitigation. The popularity of mitigation
equipment is explained by it being the only place where the customer has control
over the situation. Both changes in the supply as well as improvement of the
equipment are often completely outside of the control of the end user. Some
examples of mitigation equipment are
• Uninterruptable power supply (UPS). This is the most commonly used device
to protect lowpower equipment (computers, etc.) against voltage sags and interruptions.
During the sag or interruption, the power supply is taken over by an internal
battery. The battery can supply the load for, typically, between 15 and 30
min.
• Static transfer switch. A static transfer switch switches the load from
the supply with the sag to another supply within a few milliseconds. This limits
the duration of a sag to less than one half cycle, assuming that a suitable
alternate supply is available.
• Dynamic voltage restorer (DVR). This device uses modern power electronic
components to insert a series voltage source between the supply and the load.
The voltage source compensates for the voltage drop due to the sag. Some devices
use internal energy storage to make up for the drop in active power supplied
by the system. They can only mitigate sags up to a maximum duration.
Other devices take the same amount of active power from the supply by increasing
the current.
These can only mitigate sags down to a minimum magnitude. The same holds for
devices boosting the voltage through a transformer with static tap changer.
• Motorgenerator sets. Motorgenerator sets are the classical solution for
sag and interruption mitigation with large equipment. They are obviously not
suitable for an office environment but the noise and the maintenance requirements
are often no problem in an industrial environment.
Some manufacturers combine the motorgenerator set with a backup generator;
others combine it with powerelectronic converters to obtain a longer ridethrough
time.
3.6 Improving Equipment Voltage Tolerance
Improvement of equipment voltage tolerance is probably the most effective
solution against equipment trips due to voltage sags. But as a shorttime solution,
it is often not suitable. In many cases, a customer only finds out about equipment
performance after it has been installed. Even most adjustablespeed drives
have become offtheshelf equipment where the customer has no influence on
the specifications.
Only large industrial equipment is custommade for a certain application,
which enables the incorporation of voltagetolerance requirements in the specification.
Apart from improving large equipment (drives, processcontrol computers),
a thorough inspection of the immunity of all contactors, relays, sensors, etc.
can significantly improve the voltage tolerance of the process.
3.7 Different Events and Mitigation Methods
FIG. 6 showed the magnitude and duration of voltage sags and interruptions
resulting from various system events. For different events, different mitigation
strategies apply.
Sags due to shortcircuit faults in the transmission and subtransmission system
are characterized by a short duration, typically up to 100 ms. These sags are
very hard to mitigate at the source and improvements in the system are seldom
feasible. The only way of mitigating these events is by improvement of the
equipment or, where this turns out to be unfeasible, installing mitigation
equipment. For lowpower equipment, a UPS is a straightforward solution; for
highpower equipment and for complete installations, several competing tools
are emerging.
The duration of sags due to distribution system faults depends on the type
of protection usedranging from less than a cycle for currentlimiting fuses
up to several seconds for overcurrent relays in underground or industrial distribution
systems. The long sag duration also enables equipment to trip due to faults
on distribution feeders fed from other HV/MV substations. For deep longduration
sags, equipment improvement becomes more difficult and system improvement easier.
The latter could well become the preferred solution, although a critical assessment
of the various options is certainly needed.
Sags due to faults in remote distribution systems and sags due to motor starting
should not lead to equipment tripping for sags down to 85%. If there are problems,
the equipment needs to be improved. If equipment trips occur for longduration
sags in the 70%80% magnitude range, changes in the system have to be considered
as an option.
For interruptions, especially the longer ones, equipment improvement is no
longer feasible. System improvements or a UPS in combination with an emergency
generator are possible solutions here.
