Short and long interruptions- UNIT-II-POWER QUALITY

BY ,
DANIEL MANOJ NETHALA
ASSISTANT PROFESSOR
DEPARTMENT OF EEE

 Interruptions are classified by IEEE 1159 into
either a short-duration or long-duration
variation. However, the term “interruption”
is often used to refer to short-duration
interruption, while the latter is preceded by
the word “sustained” to indicate a long-
duration. They are measured and described
by their duration since the voltage
magnitude is always less than 10% of
nominal.

 Interruption is defined as the decrease in
the voltage supply level to less than 10%
of nominal for up to one (1) minute
duration.
 They are further subdivided into:
Instantaneous (1/2 to 30 cycles),
Momentary (30 cycles to 3 seconds) and
Temporary (3 seconds to 1 minute).

 Interruptions mostly result from reclosing
circuit breakers or reclosers attempting to
clear non-permanent faults, first opening and
then reclosing after a short time delay.
 The devices are usually on the distribution
system, but at some locations, momentary
interruptions also occur for faults on the sub
transmission system.
 The extent of interruption will depend on
the reclosing capability of the protective
device.

 For example, instantaneous reclosing will
limit the interruption caused by a temporary
fault to less than 30 cycles. On the other
hand, time delayed reclosing of the
protective device may cause a momentary or
temporary interruption.
 Aside from system faults, interruptions can
also be due to control malfunctions and
equipment failures.

 Consequences of short interruptions are
similar to the effects of voltage sags.
Interruptions may cause the following (but
not limited to):
 Stoppage of sensitive equipment (i.e.
computers, PLC, ASD)
 Unnecessary tripping of protective devices
 Loss of data
 Malfunction of data processing equipment.

 Sustained Interruption is defined by IEEE
1159 as the decrease in the voltage supply
level to zero for more than one (1) minute. It
is classified as a long duration voltage
variation phenomena.
 Sustained interruptions are often permanent
in nature and require manual intervention
for restoration.

 In addition, they are specific power system
phenomena and have no relation to the
usage of the term outage. Outage does not
refer to a specific phenomenon, but rather
to the state of a system component that has
failed to function. Furthermore, in the
context of power quality monitoring,
interruption has no relation to reliability or
other continuity of service statistics.

 Sustained interruptions are usually caused by
permanent faults due to storms, trees
striking lines or poles, utility or customer
equipment failure in the power system or mis
coordination of protection devices.
Consequently, such disturbances would result
to a complete shutdown of the customer
facility.

 Some interruptions may be preceded by a
voltage sag, particularly when these PQ
problems are due to faults on the source
system. The voltage sag occurs between the
time a fault initiates and the protective
device operates. On the faulted feeder, loads
will experience a voltage sag followed
immediately by an interruption.

The figure below illustrates a
momentary interruption during
which voltage on one phase sags
to about 20 percent for about 3
cycles, which subsequently
drops to zero for about 1.8 s
until the recloser closes back in.

Short and long interruptions- UNIT-II-POWER QUALITY

 To prevent interruptions, the utility may do the
following:

 1. Reduce incidents of system faults
 Includes arrester installation, feeder inspections, tree
trimming and animal guards
 2. Limit the number of affected customers
interrupted
 Improve selectivity through single-phase reclosers
and/or extra downstream reclosers
 3. Fast reclosing

 To protect equipment from interruptions,
end-users may use Uninterruptible Power
Supply (UPS) and other energy storage
systems. Back-up generator or Self-
generation is necessary for sustained
interruptions.
 Other solutions include the use of static
transfer switch and dynamic voltage
restorer with energy storage.

 Interruptions can be the result of
 scheduled, the customers are announced before
doing any programmed actions into the
distribution network
 accidentals, caused by the permanents or
temporary faults, generally produced by external
events, equipments faults etc.
 power system faults
 equipment failures
 control system malfunctions
 Delayed reclosing of the protective device may
cause
 a momentary or temporary interruption

A power outage (also called
a power cut, a power out,
a power blackout, power
failure or a blackout) is the loss
of the electrical power network
supply to an end user.

 There are many causes of power failures in
an electricity network. Examples of these
causes include faults at power stations,
damage to electric transmission
lines, substations or other parts of
the distribution system, a short
circuit, cascading failure, fuse or circuit
breaker operation

A customer is no longer
supplied with electricity
due to one or more
outages in the supply.

 Long interruptions are by far the most severe
power quality event; thus any document
defining or guaranteeing the quality of
supply should contain limits on frequency
and duration of interruptions.
 The international standards on power quality
do not yet give any limitations for
interruption frequency or duration.

 The European voltage quality standard EN
50160 comes closest by stating that "under
normal operating conditions the annual
frequency of voltage interruptions longer
than three minutes may be less than 10 or up
to 50 depending on the area."
 The document also states that it is not
possible to indicate typical values for the
annual frequency and durations of long
interruptions.

 Many customers want more accurate limits
for the interruption frequency Therefore,
some utilities offer their customers special
guarantees, sometimes "power quality
contracts The utility guarantees the
customer that there will more than a certain
number of interruptions per year.
 If this maximum number of interruptions is
exceeded in a given year, the utility will pay
a certain amount of money per interruption
to the customer.

This can be a fixed amount per
interruption, defined n the contract,
or the actual costs and losses of the
customer due to the interrupt Some
utilities offer various levels of
quality, with different costs.

 The number of options is almost unlimited:
customer willingness to pay extra for higher
reliability and utility creativity are the main
influencing factors at the moment.
 Technical considerations hot super to play
any role in setting levels for the maximum
number of interruptions or the cost of the
various pins For a customer to make a
decision about the be option, data should be
available, not only about the average
interruption frequency but also on the
probability distribution of the number of
interruptions per year

 Contractual agreements about the voltage
quality are mainly aimed at industrial customers.
 But also for domestic customers, utilities offer
compensation.
 Utilities in the UK be to offer a fixed amount to
cash customer interrupted for longer than hours
In The Netherlands a court has ruled that
utilities have to compensate the customers for
all interruption costs, unless the utility can
prove that they are not blame for the
interruption. Also in Sweden some utilities offer
customers compensation for the interruption

 The inconvenience of an interruption
increases very fast when its duration en few
hours This holds especially for domestic
customers.
 Therefore it makes a not reduce in number
of interruptions (which might be very
expensive) but the duration Limiting the
duration of interruptions is a basic
philosophy in power system and operation in
almost any country. In the U.K., as an
example, the duration of the interruption is
limited in three ways:

 The Office of Electricity Regulation (OFFER) sets
targets for the percentage of interruptions
lasting longer than 3 hours and for the
percentage of interruptions lasting longer than
24 hours. These are so-called "overall standings
of service.
 The distribution company pays all customers
whose supply is interrupted for longer than 24
hours. This is a so called guaranteed standard of
service.
 The design of the system is such that a supply
interruption is likely to be restored within a
certain time.

To consider interruptions of the
supply in the design and operation
of power system, the inconvenience
due to interruptions needs to be
quantified one way or the other.
The term inconvenience is rather
vogue and broad.

Additional investment does not
always give a more reliable system:
an increase in the number of
components could even decrease the
reliability.
 Reliability is not a single-
dimensional quantity. Both
interruption frequency and duration
of interruption influence the
interruption costs.

 Direct costs
 Indirect costs
 Non material inconvenience
 Costs per interruption
 Costs per interrupted KW
 Costs per Kwh not delivered
 Costs of interruption rated to the peak load
 Costs per interruption rated to the annual
consumption

 There is no shading scale of reliability and costs.
The system designer can choose between a
limited number of design options; sometimes
there are just two options available. The choice
becomes simply a comparison of advantage and
disadvantages of the two options,
 The two cost terms cannot simply be added. One
term (building and opera notional costs) has a
small uncertainty, the other term (interruption
costs) has large uncertainty due to the
uncertainty in the actual number and duration
interruptions. A more detailed risk analysis is
needed than just adding the expected costs.

 These are the costs which are directly
attributable to the interruption. The standard
example for domestic customers is the loss of
food in the refrigerator, For industrial customers
the direct costs consist, among others, of lost
raw material. lost production, and salary costs
during the non-productive period.
 For commercial customers the direct costs are
the loss of profit and the salary costs during the
non-productive period.
 When assessing the direct costs one has to be
watchful of double-counting. One should at first
subtract the savings made during the
interruption.

 Indirect costs. The indirect costs are much
harder evaluate and in many cases not simply
to express in amount of money.
 A company can lose future orders when an
interruption leads to delay in delivering a
product. A domestic customer can decide to
take an insurance against loss of freezer
contents:
 A commercial customer might install a
battery backup. A large industrial customer
could even decide to move a plant to an area
with less supply interruptions.

 The main problem with this cost term is that
it cannot be attributed to a single
interruption, but to the real or perceived)
quality of supply as a whole Non-material
inconvenience.
 Some inconvenience cannot be expressed in
money. Not being able to listen to the radio
for 2 hours can be a serious inconvenience,
but the actual costs are zero.

 In industrial and commercial environments,
the non-material inconvenience can also be
big without contributing to the direct or
indirect costs.
 A way of quantifying these costs is to look at
the amount of money a customer is willing to
pay for not having this Interruption

 Costs per interruption. For an individual
customer the costs of an interrupt of
duration d can be expressed in dollars.
 There is no confusion possible about this. For
simplicity, we neglect the fact that the costs
not only depend on the duration but on many
other factors as well.
 The costs per interruption can be determined
through an inventory of all direct and
indirect costs. .

 Costs per interrupted kW, Let C(d) be the costs
of an interruption of d for customer i, and L, the
load of this customer when duration there would
not bae been an interruption. The costs per
interrupted kW are defined as

𝑪 𝒊 (𝒅)
𝑳𝒊
 and are expressed in $/kW. For a group of
customers experiencing the same interruption,
the costs per interrupted kW are defined as the
ratio of the total costs of the interruption and
the total load in case there would not have been
an interruption:

⅀𝒊 𝑪 𝒊 (𝒅)
⅀𝒊 𝑳𝒊

 Costs per kWh not delivered. In many studies
the assumption is made that the cost of an
interruption is proportional to the duration
of the interruption. The cost per kWh not
delivered is defined as

𝑪 𝒊 (𝒅)
𝒅𝑳 𝒊
 and is constant under the assumption. The
cost per kWh is expressed in S/kWh. For a
group of customers the cost per kWh not
delivered is defined as
⅀𝒊 𝑪 𝒊
𝒅⅀𝒊 𝑳𝒊

 Some utilities obtain an average cost per
kWh not delivered for all their customers.
This value is assumed constant and used as a
reference value in system operation and
design.
 The term "value of lost load" is sometimes
used for the cost per kWh not delivered
averaged over all customers.

 Cost of interruption related to the peak load.
A problem in surveys is that the actual load
of individual customers in case there would
not have been a interruption is often not
known.
 One should realize that surveys cons
hypothetical interruptions, rarely actual
ones. For industrial and commercial
customers the peak load is much easier to
obtain, as it is typically part of the supply
contract.

 The cost of an interruption can be divided by
the peak load, to get a value in $/kW. Some
care is needed when interpreting this value,
as it is not the same as the cost per kW
interrupted (also in $/kW).
 For planning purposes the cost of
interruption related to the peak load can still
be a useful value. The design of a system is
based for a large part on peak load, so that
rating the cost to the peak load gives a
direct link with the design.

 Cost per interruption related to the annual
consumption. For domestic customers it is
easier to obtain the annual consumption than
the peak load. Rating cost of an interruption
to the annual consumption gives a value in
$/kWh.
 Note that this has no relation to the costs
per kWh not delivered.

The power system is often divided
into three functional parts, each
with its own specific design and
operation problems and solutions:
Generation
Transmission
Distribution

In the reliability analysis a similar
distinction is made between three
so-called hierarchical levels of
reliability
Level I: generation
Level II: generation and transmission
Level III: generation, transmission
and distribution

Annual peak load
Preventive Maintenance
Load duration curve
Derated states
Operation reserve

 Level II reliability concerns the availability of
power at so-called bulk supply points:
typically transmission substations where
power is transformed down to distribution
voltage.
 The power not only has to be generated but
also transported to the customers. The
availability of sufficient lines or cables has to
be taken into account.
 Level II reliability studies are much more
difficult than level 1 studies, and are still
under considerable development.

Overloading of lines
Reliability of the protection
Dynamic system behavior
Common mode outages
Weather related outages
 Normal weather
 Adverse weather
 Major storm disaster

Radial systems
Duration of an interruption
The availability of the
alternative supply
Adverse weather
Embedded generation

 There is some serious confusion about
terminology on interruptions of different
duration.
 Terms like short interruptions, momentary
interruptions, temporary interruption,
instantaneous interruption, and transient
outages are all used with more or less the
same meaning.
 The definition of short interruptions used for
this chapter is not based on duration but on
the method of restoring the supply. This
chapter (short

 interruptions) discusses automatic
restoration, where Chapter 2 (long
interruptions) discusses manual restoration.
 Below, an overview is given of the various
terms and definitions used in t European
standard EN 50160 and in three IEEE
standards. The definition EN 50160 are
identical to the IEC definitions.
 EN 50160
 Long interruption longer than three minutes.
 Short interruption up to three minutes.

 IEEE Std.1159-1995
 This standard is considered by many as providing
the basic power definitions It distinguishes
between momentary, sustained, and temporary
interruptions. Note the overlap between
sustained and temporary interruptions-
 Momentary interruption between 0.5 cycles and
3 seconds.
 Sustained interruption: longer than 3 seconds.
 Temporary Interruption between 3 seconds and 1
minute.

 IEEE Std. 1250-1995
 This standard was published at about the same
time as IEEE Std. 1139-19 but it uses somewhat
different definitions. The difference is especially
striking for interruptions.
 Instantaneous interruption between 0.5 and 30
cycles (half a second).
 Momentary Interruption between 30 cycles and 2
seconds.
 Temporary interruption between 2 seconds to 2
minutes.
 Sustained interruption: longer than 2 minutes.

 IEEE Std. 859-1987
 This somewhat older standard document gives
definitions for terms related to power system
reliability. A distinction is made between different
types of outages based on the duration of the outage.
This standard does not me specific time range but
uses the restoration method to distinguish the
different types. Although outages and interruptions
are different phenomenal Section 2.1.3) they related
closely enough to compare the terminology.
 Transient outages are restored automatically.
 Temporary outage is restored by manual switching –
 Permanent outages is restored through repair or
replacement.

 Figure 3.1 shows an example of an overhead
distribution network.
 Each feeder consists of a main feeder and a
number of lateral conductors.
 Most faults on lines are transient: they
require operation of the protection, but do
not cause permanent damage to the system.
 A typical cause of a transient fault is a
lightning stroke to overhead line.

 The lightning stroke injects a very high
current into the line causing very fast rising
voltage.
 The lightning current varies between 2 and
200 kA in peak value.
 The typical lightning current has a peak
value of Ipeak= 20 kA which is reached within
1 µs after its initiation.

If the wave impedance Zwave of
the line is 200ohms, the voltage
can theoretically reach a value
of
 𝑉𝑝𝑒𝑎𝑘 =
𝑍𝑤𝑎𝑣𝑒
2
𝐼 𝑝𝑒𝑎𝑘=100Ώ×20KA=2MV

 The voltage will never reach such a value in
reality (with the possible exception of
transmission systems with operating voltages of
400 kV or higher), because a flashover to ground
or between two phases will result long before
the voltage reaches such a high value.
 The result is an arcing fault between one phase
and ground or between two or more phases with
or without ground.
 Soon after the protection removes the faulted
line from the system, the arc disappears.
Automatic reclosing will restore the supply
without any permanent damage to the system.

 Also, smaller objects causing a temporary
path to ground will only cause a transient
short circuit.
 The object (e.g. a small branch fallen from a
tree) will either drop to the ground or
evaporate due to the high current during the
fault, leaving only an arc which disappears
again soon after the protection intervenes.
 The duration of an interruption due to a
transient fault can thus be enormously
reduced by automatically restoring the
supply after an interruption.

 In case of a fault somewhere on the feeder, the
circuit breaker opens instantaneously and closes
again after a "reclosing interval" or "dead time"
ranging from less than one second up to several
minutes.
 There is of course a risk that the fault was not a
transient one but permanent. In that case the
protection will again notice a large overcurrent
after reclosurer leading to a second trip signal.
 Often the recloser gives the fault a second
chance at extinguishing, by means of a longer
tripping time and/or a longer reclosing interval.

The fuse saving scheme typically
uses a low set instantaneous
overcurrent element which will trip
the feeder breaker before
the fuse branch can blow, and the
breaker is then immediately
reclosed.

 A practice associated with reclosing and short
interruptions is "fuse saving. In Fig 3.1 the
laterals away from the main feeder are
protected by means of expulsion fuses.
 These are slow fuses which will not trigger when
a transient fault is cleared by the main
breaker/recloser.
 Thus, a transient fault will be cleared by the
recloser and the supply will be automatically
restored.
 A permanent fault can also be cleared by the
main breaker, but that would lead to a long
interruption for all customers fed from this
feeder. Instead, a permanent fault is

 An expulsion fuse is a vented fuse in which
the expulsion effect of the gases produced
by internal arcing, either alone or aided by
other mechanisms, results in current
interruption. An expulsion fuse is not
current limiting and, as a result, limits the
duration of a fault on the electrical system,
not the magnitude

 cleared by an expulsion fuse. To achieve this,
the recloser has two settings an instantaneous
trip and a delayed trip.
 The protection coordination should be such that
the instantaneous trip is faster than the
expulsion fuse and the delayed trip slower, for
all possible fault currents.
 From the above description we can conclude
that the following trade-off has been made a
short interruption for all customers (fed from
this feeder) instead of a long interruption for
some customers.
 The alternative would be more long
interruptions, however, not every short
interruption would become a long interruption.

 The combination of reclosing and fuse
saving, as described above, leads different
voltage magnitude events for different
customers.
 Figure 3.2 shows the events due to one
reclosing action as experienced by a
customer on the faulty feeder (indicated by
"1" in Fig 3.1) and by a customer on another
feeder fed from substation bus (indicated by
"2").
 In Fig. 3.2, A is the fault-clearing time and B
the reclosing interval.

 The customer on the faulted feeder (solid
line) will experience a decrease in voltage
during the fault, similar in cause and
magnitude to a voltage sag.
 The difference between the two customers is
in the effect of the fault clearing.
 For customer on the non faulted feeder, the
voltage recovers to its pre-event value
customer will only experience a voltage sag.
For the customer on the faulted e the
voltage drops to zero

 The customer on a neighboring feeder (dashed
line) will see a voltage sag with 2 duration equal
to the fault-clearing time.
 The moment the recloser opens, the voltage
recovers. If the fault is still present at the first
recloser, the customer on the non faulted feeder
will experience a second voltage sag.
 Customers on the faulted feeder will experience
a second short interruption or a long
interruption.
 Figure 3.3 [11] shows an actual recording of a
short interruption.

 The top figure corresponds to the dashed line
in Fig. 3.2 (customer on a non fault feeder).
 The bottom figure is for a customer on the
faulted feeder (solid line in Fig. 3,2).
 The fault-clearing time is about two cycles,
the dead time about two seconds.
 The first recloser is not successful, the
second one is. The top figure shows a voltage
sag to about 75% of two-cycle duration, the
bottom figure a voltage reduction to 50% for
two cycles followed by zero voltage for
about two seconds.

 When comparing Fig. 3.2 and Fig. 3.3, note that
the horizontal axis of Fig. 3.2 is not to scale, B is
much larger than A.
 This is the typical situation. The fault-clearing
time (A) is only a few cycles, whereas the
reclosing time (B) can be up to several minutes.
 Another example of the initiation of a short
interruption is shown in Fig. 3.4 (3) We see that
the voltage magnitude initially drops to about
25% of nominal and to almost zero after three
cycles.
 The spikes in the voltage are due to the are
becoming instable around the current zero-
crossing. Apparently the arc gets more stable
after two cycles.

 The moment the circuit breaker in Fig. 3.1
opens, the feeder and the load fed from it
are no longer supplied.
 The effect of this is normally that the
voltage drops to zero very fast.
 There are, however, situation.is in which the
voltage drops to zero relatively slow, or even
remains at a nonzero value. The latter would
strictly speaking not be an interruption, but
the origin is similar to that of an
interruption so that a short description of the
phenomenon is applied here.

 All this assumes that the short-circuit fault is
no longer present on the feeder.
 As long as the fault is present, all above-
mentioned machines feed into the fault so
that the feeder voltage remains low.
 The fault-current contribution makes that
the arc is less likely to extinguish, but after
extinguishing of the arc there will be a
chance of a remaining voltage on the feeder.

For interruptions due to
incorrect protection
intervention there is no short
circuit fault present on the
feeder and the machines
connected to the feeder may
cause a temporary or permanent
nonzero voltage.

 As short interruptions are due to automatic
switching actions, their recording requires
automatic monitoring equipment.
 Unlike long interruptions, a short
interruption can occur without anybody
noticing it. That is one of the reasons why
utilities do not yet collect and publish data
on short interruptions on a routine basis.
 One of the problems in collecting this data
on a routine basis is that some kind of
monitoring equipment needs to be installed
on all feeders.

 A number of surveys have been performed to
obtain statistical information about voltage
magnitude variation and events. With those
surveys, monitors were installed a number of
nodes spread through the system.
 The surveys will be discussed in more detail in
Chapter 6. As with long interruptions,
interruption frequency and duration of
interruption are normally presented as the
outcome of the survey.
 Again like with long interruptions much more
data analysis is possible, e.g., interruption
frequency versus time of day or time of year,
distributions for the time between events,
variation among customers.

 The number of short interruptions has been
obtained by various power quality surveys.
Comparison of the numbers obtained by each
survey gives information about the average
voltage quality in the various areas.
 A comparison between the number of short
interruptions counted at various places in the
system can teach us how the interruptions
"propagate" in the system.
 Such a comparison is made in Table 3.1 for two
large North American surveys: the EPRI survey
and the NPL survey (54) The EPRI survey
monitored both distribution substations and
distribution feeders.

 From Table 3.1 we see that the overall trend is
for the number of short interruptions to increase
when moving from the source to the load. This is
understandable as there are more possible
tripping points the further one moves towards
the load.
 Especially interruptions lasting several seconds
and longer mainly originate in the low-voltage
system.
 For interruptions less than one second in
duration, the frequency remains about the same,
which makes us conclude that they probably
originate in the distribution substation or even
higher up in the system.

 The large number of very short interruptions
(less than six cycles) on distribution feeders is
hard to explain, especially as they do not show
up in the low-voltage data.
 Similar conclusions can be drawn from the CEA
survey (69) and from the EFI survey 167), some
results of which are shown in Tables 3.2 and 3.3.
We again see a larger number of interruptions,
mainly of 1 second and longer, for low-voltage
than for medium-voltage systems.
 Both the Canadian (CEA) and the Norwegian (EFI)
data show a considerable number of very short
interruptions, for which no explanation has been
found yet.

 A direct consequence of reclosing actions is that a
customer may experience two A or more events
within a short interval. When the short-circuit fault is
still present upon the first recloser, the customers
fed from the faulted feeder will experience a second
events.
 This is another short interruption if a second attempt
at reclosing is made Otherwise the second event will
be a long interruption. A customer fed from a non
faulted feeder experiences two voltage sags in a
short period of time.
 For a few years a discussion has been going on about
whether to count this as one event of a multiple
events (20J. The most recent publications of North
American survey consider a 1-minute or 5-minute
window.

 If two or more events take place within such
a window, they are counted as one event.
 The severity of the multiple event (e,
magnitude and duration) is the severity of
the most severe single event within the
window. Some examples of the working of a
"five-minute filter" are shown in Fig.
 Using such filter is suitable for assessment of
the number of equipment trips as the
equipment will trip on the most severe event
or not at all.

 The cumulative effect of the events is
neglected, but the general impression is that this
effect is small.
 This has however not be confirmed by
measurements yet. In some cases it could still be
needed to know the total event frequency, thus
counting all events even if they come very close.
 Two possible applications are components which
show accelerated aging due to short under
voltage events, and (2) equipment which only
trips during a certain fraction of its load cycle

 In the latter case the equipment has a
probability to trip during each of the three
events, and the total probability is of course
larger than the probability to trip during the
most severe event only.
 The NPL low-voltage data for short interruptions
have been presented with and without the
above-mentioned filter in Table 3.4 (54].
 The three rows give, from top to bottom: the
number of short interruptions when each event
is counted as one event no matter how close it is
to another event; the number of events when
multiple events within a 5-minute interval are
counted as one event; the reduction in number
of events due to the application of this filter

 The opening of the faulted phase during a single-
phase to ground fault.
 Single-phase auto-reclosing (SPAR) is used for
restoring power supply to clear temporary
single-phase to ground fault in medium-voltage
distribution systems.
 A relay protection scheme that provides for
single pole tripping and reclosing is one that,
after it detects a fault and establishes that
tripping should take place, will trip only the
faulted phase on single-line-to-ground faults and
all three phases on all multi-phase faults.

 Single-phase tripping is used in
transmission systems to maintain
synchronicity between both sides of a
line.
 Single-phase tripping is rarely used in
distribution or low-voltage systems.
 Not only will it require more expensive
equipment, but it will also reduce the
chance of a successful reclosure.

 The fault current continues to flow via the
nonfaulted phases.
 This reduces the chance that the fault will
extinguish and thus increases the number of
reclosure attempts and the number of long
interruptions.
 But if the reclosure is successful, single-
phase tripping has clear advantages over
three-phase tripping and therefore justifies
being discussed here.

 We will have a look at the voltages experienced
by the customer during single-phase tripping.
 A distinction is made between two distinctly
different situations, both assuming a single-
phase-to-ground fault followed by tripping of the
faulted phase.
 The low-impedance path between the faulted phase
and ground (the fault) is still present so that the
voltage in the faulted phase remains zero or close to
zero. We will call this the "during-fault period.
 The fault has extinguished, the short circuit has now
become an open circuit because the breaker in that
phase is still open. This we will call the post-fault
period."

Voltage during Fault period
Voltage during post Fault
period
Current during fault period

 The phase-to-neutral voltages in the during-
fault period are, with a the faulted phase
 𝑉𝑎 = 0
 𝑉𝑏 = (−
1
2
−
1
2
𝑗 3 )𝐸
 𝑉𝑐 = (−
1
2
+
1
2
𝑗 3 )𝐸 (3.5)

 with E the magnitude of the pre-event
voltage.
 It has been assumed here that the pre event
voltages form a balanced three-phase set,
and that the voltage in the faulted phase is
exactly equal to zero.
 We will in most of the remainder of this book
use per unit voltages, with the pre-event
voltage magnitude as base.
 In that case we get E = 1 and (3.5) becomes

 𝑉𝑎 = 0
 𝑉𝑏 = −
1
2
−
1
2
𝑗 3
 𝑉𝑐 = −
1
2
+
1
2
𝑗 3
E=1

 Figure 3.9 shows the phase-to-neutral voltages
as a phasor diagram.
 In this and sub sequent phasor diagrams the
during-event voltage is indicated via solid lines,
the pre- event voltage (i.e,, the balanced three-
phase voltage) via dotted lines, if different from
the during-event voltage.
 If single-phase tripping would take place in a
low-voltage network, the voltages in Fig. 3.9
would be the voltages experienced by the
customers Only one out of three customers
would experience an interruption.
 The others would not notice anything. Single-
phase tripping would thus reduce the number of
interruption events by a factor of three.

 For tripping taking place on medium-voltage
feeders, the phase-to-phase voltages are of
more importance.
 Large equipment fed at medium-voltage
level is in most cases connected in delta;
small single-phase equipment tends to be
connected between a phase and neutral but
at a lower voltage level fed via a delta-star
connected transformer.
 In both cases the equipment experiences the
pu value of the phase-to-phase voltage at the
medium-voltage level.

 The factor 3 is needed because 1 pu of the line
(phase-to-phase) voltage is 3 times as big as I pu
of the phase (phase-to-neutral) voltage. The
multiplication with j results in a rotation over
90° such that the axis of symmetry of the
disturbance remains along phase a and along the
real axis. The transformation in (3.7) will be the
basis of a detailed analysis of unbalanced
voltage sags in the forthcoming chapters, When
we leave away the prime ', we obtain the
following expressions for the voltages due to
single-phase tripping at the terminals of delta-
connected equipment:

 Generally, a single line-to-ground fault on a
transmission line occurs when one conductor
drops to the ground or comes in contact with
the neutral conductor.
 Such types of failures may occur in power
system due to many reasons like high-speed
wind, falling off a tree, lightning, etc.

 When the fault extinguishes, the situation in the
faulted phase changes from a short circuit to an
open circuit.
 In many cases a change in voltage occurs, thus
the resulting voltage is no longer equal to zero.
 The voltage in the faulted phase depends on the
type of load connected To calculate this voltage
we need to consider the coupling between the
phases or use the theory of symmetrical
components.
 To analyze an open circuit, the system has to be
modeled as seen from the open circuit point.
This results in three equivalent circuits: for the
positive sequence, for the

 negative sequence, and for the zero sequence. These three
networks are shown in Fig 3.11. Zs1. Zs2, and Zso are
positive, negative, and zero-sequence impedance of the
source, ZL1. ZL2, and ZL0 are positive, negative, and zero-
sequence impedance of the load, ΔV1 ΔV2, and ΔV0. are
positive, negative, and zero-sequence voltage drop at the
open-circuit point, and E, is the positive-sequence source
voltage.
 Negative and zero sequence source voltages are assumed
zero, and the load is assumed not to contain any sources.
 Below we again assume E = 1 Sequence voltages and
currents at the open-circuit point can be calculated for
different types of open-circuit faults, by connecting the
three sequence networks in different ways.
 For a single-phase open circuit, the voltage difference in
the two non faulted phases is zero and the current in the
faulted phase is zero:

∆𝑉𝑏= 0
∆𝑉𝑐= 0
 𝐼 𝑎 = 0
Where a is the faulted (open
circuited) phase.

 Transforming these equations to symmetrical
component gives the following set of
equations
 𝐼1 + 𝐼2 + 𝐼3 = 0
∆𝑉1=∆𝑉2
∆𝑉1=∆𝑉0

Short and long interruptions- UNIT-II-POWER QUALITY

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