Protection Measurements
and Controls
This chapter presents some basic control configurations for protective systems. The method of
connecting protective devices into the power system are presented, and some of the problems
of making accurate observations of system conditions will be explored. We also investigate the
methods by which circuit breakers are controlled, both for manual and automatic operation.
Finally, we present some basic information on instrument transformers, which represent the
interface between the protective system and the power system.
2.1 GRAPHIC SYMBOLS AND DEVICE IDENTIFICATION
Graphic symbols are important in communicating protective system information. As an introduction to the basic relaying circuits, we review briefly the IEEE standards for graphic symbols
that are used in this book.
The symbols commonly used in protection engineering are IEEE standards, and many
of them have also been adopted by the International Electrotechnical Commission (IEC) [1J.
The symbols most used in protective systems are those shown in Figure 2.1.
The first two symbols show the correct graphical symbol for electrical contacts. The
"a" contact is a normally-open contact and is always depicted in drawings in the open position
even though, in a particular application, the contact may be nearly always closed. This permits
us to distinguish immediately that this contact is one that is open when no current flows in its
operating coil. The a contact is sometimes called a "front contact."
The second contact, or "b" contact, is always illustrated in the closed position, since it
always returns to this position when there is no current in its operating coil. The b contact is
also referred to as a "back contact." The operating coils that are associated with relay contacts
and with the circuit breakers are depicted as shown in Figure 2.1 (older diagrams may show
operating coils as circles, but this practice is depreciated).
The graphic symbols for current and potential transformers are also illustrated in Figure 2.1. Note that these transformers are shown with polarity dots to clarify the phase rela17
18
Chapter 2 • Protection Measurements and Controls
--L
T
Front or
"a" Contact
Current
Transformers
Voltage or
Potential
Transformers
*
Back or
"b" Contact
~
Operating
Coil
et=
~
• •
:3t:
3E
Figure 2.1 Graphic symbols used in protective
relaying [1].
tionship of the currents and voltages. The IEEE standards note that the potential transformer
may also be referred to as a "voltage transformer." In practice, the more common terms are
current transformer, or CT, and potential transformer, or PT (or voltage transformer, VT) [2].
These terms are used in this book.
Protective relays have two circuits or sets of circuits, one for ac and one for de quantities.
The ac circuits are replicas of the ac quantities in the actual power system, which are transformed
to suitable magnitudes by current and potential transformers. The de circuit controls the
tripping of the circuit breaker by permitting current to flow through the breaker trip coil under
control of one or more relays. The relays provide the control intelligence and a suitable set of
contacts to control the flow of current in the de trip circuit of the circuit breakers.
Protective system control drawings also use a formal system of device function numbering to clearly identify objects that are used in graphic displays. These numbers conform to
ANSIIIEEE Standard C37 .2, which defines the devices and their function, and gives each device
a function number for use in drawings, diagrams, manuals, and other publications. A partial
listing of these standard device function numbers is given in Appendix B. The ANSIIIEEE
Standard should be consulted for more complete information [3].
Using device numbers, each relay coil or contact may be identified as to the type or
function of the device to which that item belongs. This provides a shorthand notation for use
on drawings and other media that is brief and is readily understood.
2.2 TYPICAL RELAY CONNECTIONS
As an introduction to relay and circuit breaker connections, consider the system shown in
Figure 2.2, where a radial line is protected by time-overcurrent relays (51) in each phase.
Only the connection in one phase is illustrated for simplicity. The circuit breaker (52) control
circuit consists of a battery that is connected through the circuit breaker auxiliary contacts (52a)
and the circuit breaker trip coil (52TC), and finally to the relay contact (51). During normal
operation, the circuit breaker is closed and load currents are flowing (downward in the figure).
The circuit breaker front contacts (52a) are closed under this condition. Think of the "a" in
52a as meaning in agreement with the circuit breaker main contacts. 1 If a fault is detected
such that the current in the relay coil exceeds a given preset threshold value, the relay will
close its contacts in a measured time, which depends on the magnitude of the current and on
the relay characteristics. This will cause current to flow in the circuit breaker trip coil (52TC),
I There may be other contacts in a relay control scheme that use the letter "a" in the contact identification, but
such contacts are not part of the circuit breaker and their open/close position is independent of the circuit breaker state.
19
Section 2.2 • Typical Relay Connections
tripping the circuit breaker main contacts and also the auxiliary contacts. Tripping the main
contacts removes the fault from the system and allows the relay to reset itself in a short time,
which depends on the relay design. Tripping the auxiliary contacts opens the control circuit
and interrupts the flow of current in that circuit.
-e--------------A
- .....- -. .- - - - - - - - - - B
-+---.....--~.....------C
52
52
Bus
52
+
Battery
Figure 2.2
~ simple relay and circuit breaker
control circuit.
Protective
Line
-=-
Circuit
Breaker
The control circuit of Figure 2.2 is simpler than that found in most practical applications.
A practical circuit would include a relay for each phase conductor and may have a fourth relay
to measure ground currents. Also, since most faults are temporary, it may be desirable to
include a means of automatically reclosing the circuit breaker after allowing time for the fault
to deionize. These additional features will be introduced later. Finally, we note that this is a
special case, being a radial line, making a simple overcurrent relay adequate to provide the
necessary selectivity and control required. Most transmission lines are not operated radially
and require more elaborate relay protection. Figure 2.3 shows a typical ac connection for a
relay that requires both current and potential supplies. The connection of Figure 2.3 is typical
of that used for a directional relay. Note that relay element 1 sees current fa and voltage Vbc ,
and that these quantities are nearly in phase for a transmission line fault, which usually has the
current lagging the phase voltage by nearly 90 degrees. One reason the connection of Figure 2.3
has been popular goes back to a principle of electromechanical relays, where having the relay
current and voltage in phase on a wattmeter type element produces maximum torque on the relay
element. Obviously, other connections of the current and voltage transformers are possible.
The de circuit of the relay is the circuit breaker tripping circuit, as shown in Figure 2.4,
which shows a tripping circuit that could be used with the relay connections of Figure 2.3.
This de trip circuit incorporates a holding coil or "seal-in" relay labeled "5" in the figure. The
operation is as follows. If one of the relay elements detects a fault condition, the corresponding
relay contact R is closed by the relay logic. Since the breaker auxiliary relay "a" contacts are
closed (note that the breaker is still closed) closing R causes current to flow in the circuit breaker
trip coil (TC). In many cases, the relay contacts are not designed for the relative severe duty
of interrupting the trip circuit, hence the R contacts are paralleled by the seal-in relay contacts
S, which remain closed throughout the breaker operation even though the relay contacts may
drop out. When the circuit breaker main contacts open, the breaker auxiliary contacts "a"
also open, interrupting the current flow in the de control circuit. This interruption also causes
the seal-in relay to drop out and the circuit is ready for reclosing and for tripping the next
fault.
20
Chapter 2 • Protection Measurements and Controls
- . - - - - - - - - - - - - - - - - -...- - - - - - a
- .....- ...- - - - - - - - - - - - -.....- -....- - - b
- - t - -.....-
--I--.. . .
~ c
.....- - - - - - - - - - - -.....
1
2
3
g
b
a
Phase Rotation
abc
Circuit
Breaker
a
b
c
c
fa
Unity power factor phasor
with currents in trip direction
Figure 2.3 Typical ac relay connection showing both the current and voltage supplies
(90 degree connection).
1
2
3
g
+
Battery
52TC
Circuit
Breaker
Figure 2.4 Typical dc trip circuit connection.
In small stations, where a battery supply cannot be justified, the battery can be replaced
by a capacitor that is kept charged from the ac line by a rectifier. The capacitor is sized to have
sufficient energy to trip the circuit breaker.
Another method of arranging the trip circuit is the series trip connection shown in Figure 2.5. Here, the circuit breaker must be equipped with three trip coils, labeled TC, rather
than the one coil used in the shunt trip circuit. Series trip is convenient at locations where it is
impractical to have a battery supply, such as small remote breaker locations. An arrangement
similar in philosophy is used in low-cost, distribution system oil circuit "reclosers," where the
actual line current is sometimes used as the tripping current. This saves the expense of current
transformers, but requires a trip circuit capable of handling fault current magnitudes. These
devices will be discussed further in Chapter 3.
21
Section 2.3 • Circuit Breaker Control Circuits
Figure 2.5 A series trip coil arrangement.
2.3 CIRCUIT BREAKER CONTROL CIRCUITS
The circuit breaker control circuits shown in Figures 2.2 and 2.3 are simplified and do not
illustrate typical circuits that are found in the industry. One shortcoming of these circuits is
that they have no means of manual operation of the breaker, either for opening or closing. Other
features are required in a practical system. These features will be discussed in connection with
the description of a typical control circuit.
Consider the control circuit shown in Figure 2.6, which is a complete tripping and closing
circuit for a circuit breaker. Here, the protective relay contacts are shown as a single contact
labeled "R" and this should be understood to include as many contacts as are actually available
from the various relays at a given installation.
+
52
X
52
Y
52
C
Figure 2.6 Typical circuit breaker control circuit.
This control circuit, which is often called the X-Y control scheme, is designed to provide
several unique safeguards, as follows:
22
Chapter 2 • Protection Measurements and Controls
1. The control is electrically trip free.
2. The control includes an anti-pumping feature.
3. A provision for reclosing is provided.
First, we examine the general concepts of the control scheme. Then we shall examine
the above special features. Contacts in Figure 2.6 labeled 101 are manual control switches.
There are three of these switches:
IDle: Manual closing contact
101T: Manual tripping contact
IOISC: Manual slip contact
First, assume that the breaker is open, and the green light is on, indicating a non-energized
breaker. The operator now wishes to manually close the breaker. This is accomplished by
manually closing contact IOIC. Since the breaker is initially open, contacts 52a and 52aa are
both open. Similarly, contacts 52b are closed. Closing IOIC momentarily energizes coils 52X
since 52Y "b" contacts are closed. Coil52X picks up its respective contacts in the close circuit
causing current to flow through the circuit breaker closing coil 52C, thereby closing the circuit
breaker. Another 52X contact (to the left of IOIC) seals in the closing contact IOlC.
Now, when the breaker main contacts close, the 52 auxiliary contacts change their
open/close status. Thus, 52aa closes, which picks up coil 52Y, thereby opening the 52X
coil and de-energizing the closing coil 52C. Note that 52b opens, which assures that the IOIC
circuit remains open. Contact 52Y is used for anti-pumping and is discussed below. Thus, by
momentarily depressing IOIC, the operator puts in motion a number of control features. The
end result is that the breaker is closed, the red light is on and the green light is off. The lamp
current flows through 52T, but the current magnitude is much too small to operate the breaker.
To manually trip the breaker, the operator closes contacts 101T, which causes current to
flow through the trip coil 52T, thereby tripping the circuit breaker, turning off the red light;
and energizing the green light.
Now, suppose the operator manually closes IOIC and closes the breaker when there is
a permanent fault on the line. Moreover, suppose the operator stubbornly holds the IOIC
contacts closed. Should this occur, the first reaction after closing will be the pick up of the
relay contacts because of the fault, which trips the breaker. However, the initial breaker closure
also picks up 52aa. This energizes coil 52Y, the anti-pumping coil, which is held closed by
contacts 52Y as long as IOIC is depressed. At the same time, coil52Y also opens the circuit
of closing auxiliary coil 52X, preventing further closing of the breaker. Thus the breaker is
closed, but opens immediately and remains open, even if the operator holds 101C in the closed
position.
The reclosing feature uses contact 52LC, a latching contact, not shown in Figure 2.6.
After the breaker is tripped, the mechanical breaker closing mechanism is latched to permit
closing. This breaker action closes contacts 52LC. These contacts can be connected to a
reclosing relay, which can apply positive potential to coil 52X, initiating the automatic reclosure
of the line.
Note that it is essential that the trip circuit be energized from the battery supply, since
the ac line or bus voltage may be badly depressed during a fault condition. The breaker closing
voltage may be supplied from the ac bus, however. In this case, the control circuit is the same
except that 52X, 52Y, and 52C are connected to an ac supply.
Section 2.4 • Instrument Transformers
23
2.4 INSTRUMENT TRANSFORMERS
Protective systems for power systems are designed as system control components with the
inherent intelligence to perform the required control functions. Most of the relay equipment
involved in this function is relatively small and is mounted on low-voltage relay panels in a
control building. This makes the relay equipment convenient and safe to work with for calibration and testing. It also requires that the currents and voltages used in the relays themselves
must be transformed from transmission levels to appropriate lower voltage levels for safety
and convenience of personnel. This transformation is accomplished by means of current transformers (CT's) and potential or voltage transformers (VT's), which are collectively referred
to as "instrument transformers." These transformers are insulated for the appropriate primary
voltage level of the system and with secondary currents and voltages that match the rated values
of the relay apparatus. In North America, these secondary standard ratings are 5 amperes and
120 volts nns at 60 hertz, for CT's and VT's, respectively.
There are two concerns in applying instrument transformers; transformer selection for
accuracy and transformer connections.
2.4.1 Instrument Transformer Selection
Many instrument transformers are iron-core transformers that are designed to give secondary currents or voltages that are accurate replicas of the primary quantities. The protection
engineer must select the appropriate transformers based on the relays to be used in the protection
scheme and the connection (e.g., wye or delta) of the relays and transformers to be used [41.
For current transformers, an important criterion in selecting the correct transformation is
the maximum load current. The CT secondary current, under normal conditions, will represent
the load on the protected power system circuit and this load current will flow through the relay
circuits all the time. The relay is designed for a given maximum load current, and this value
must not be exceeded. Most relays are designed for a 5 ampere rated current, hence the CT
should be selected to provide about 5 amperes at normal load conditions.
For voltage transformers, the transformation ratio is seldom a problem, since both the
secondaries and relays are designed for 120 volt continuous service. In some applications, the
VT primaries are connected line-to-line and the secondaries line-to-neutral and this must be
taken into account.
Since many instrument transformers are iron core transformers, the quality of the iron
and its saturation characteristics are important. This is especially true for current transformers,
which might be expected to saturate when carrying fault currents. This mayor may not be a
problem, depending on the application, since even badly saturated transformers may still give
the correct tripping signal to the relays. Generally speaking, the transformers used should
be of as high quality as possible, as this tends to reduce problems and to provide better relay
accuracy. Transformer accuracy is especially important in differential relaying schemes, where
the relay sees the difference in currents.
Saturation of the current transformer can be estimated by anyone of three methods [4]:
1. The excitation (saturation) curve method
2. The formula method
3. The computer simulation method
24
Chapter 2 • Protection Measurements and Controls
In all cases, we represent the current transformer by the equivalent circuit, shown in
Figure 2.7. The primary current is transformed through the ideal transformer with ratio 1 : N.
The equivalent circuit parameters are defined as follows:
Z H = primary leakage impedance
Zs = secondary leakage impedance
RM = core loss component of the excitation branch
X M = excitation component of the excitation branch
The basic equivalent circuit is simplified as shown in Figure 2.7(b). Here the primary
leakage impedance and core loss elements are neglected. The exciting current, flowing through
the shunt excitation branch is defined as shown.
ZHN 2
Zs
JrRm~ ~xm
c::::J
l:N
e
:
~ZL
f
(a)
IH~ l:N
Is~
IH/N~
J[
Ie! ~Xm
c:=::J
e
Zs=Rs+jXs
:
f
~ZL
(b)
(c)
Figure 2.7 Equivalent circuit and phasor diagram of a current transformer.
The current transformer is evaluated by computing the accuracy by which it transforms
the primary current to the secondary current delivered to the relay. This is determined by
finding the highest secondary voltage the transformer can produce without saturation. High
secondary current makes the excitation current very large, which reduces the accuracy of the
current transformation.
From Figure 2.7(b), we define the secondary voltage as follows:
V cd
= V s = Is{Zs + ZL) = IsZB
where V s = secondary voltage, (V)
Is = maximum secondary current, (A)
Zs = secondary leakage impedance, (O)
ZL = the external impedance or "burden," (0)
ZB = the secondary burden, (0)
(2.1)
25
Section 2.4 • Instrument Transformers
In most applications, the maximum secondary current can be estimated by dividing the
known fault current by the transformation ratio of the CT.
2.4.1.1 ANSI Standard CT Accuracy Classes. The ANSI relaying accuracy classes
are specified in ANSI Standard C57.13-1993 [5J. These standards use a letter designation and
voltage rating to define the capability of the current transformer. The letter designation code
is given as follows:
Code C-Indicates that the transformer ratio can be calculated
Code T-Indicates that the ratio must be determined by test
The C classification covers most bushing current transformers with uniformly distributed
windings and any other transformers whose core leakage flux has negligible effect on the ratio,
within the defined limits. The T classification covers most wound-type current transformers
and any others whose core leakage flux affects the ratio appreciably.
An ANSI Accuracy Standard Chart for Class C current transformers is shown in Figure 2.8. Here, the transformer secondary voltage capability is plotted as a function of secondary
current for various Class C transformers. This chart gives a limit (10%) in the ratio of the CT
with a given accuracy class and a given burden. For example, for a burden of 4 ohms, the
curves specify that the ratio error for class C400 will not exceed 10% between one and 20
times normal secondary current. This computation is checked as follows:
Vs == (4Q)(5 x 20A)
== 400V
The relaying accuracy class of a given current transformer can be obtained from the manufacturer. For T-class current transformers, the manufacturer can supply typical overcurrent ratio
curves, such as the one shown in Figure 2.9 [4]. As implied by the class name, data for these
curves must be determined by test on the actual transformer,
800
700
en
~
"0
:> 600
~
r::=
·s
~
<1)
E-4
~
500
300
0
200
t.,)
<1)
e800
t---"---t---t--+---t---t-812-i-7'-t--r---t----t
400
~
oj
'"tj
~
Error will not exceed 10%
for secondary voltage equal
to or less than value
desribed by curve
ir:
100
20
.-.-,..--+-7fI'----f-,,,,,..-;-+----+----,..-f-~112
J - - - - 4 - -.....
O~~===r:::::.-L_L---L._L---L_L---L---1
Figure 2.8 ANSI Accuracy Standard Chart for
Class C current transformers.
o 5 10
20
30 40 50 60 70
Secondary Amperes
80
90
100
2.4.1.2 Excitation Curve Method. This method requires the use of an excitation curve
for the current transformers to be used. Such curves are available from the manufacturers. As
a substitute, a typical set of curves could be used, such as the curves shown in [4], which are
reproduced here as Figure 2.10. These curves represent data obtained by applying nns sec-
26
Chapter 2 • Protection Measurements and Controls
22
i-:
B-IO
20
en
.±:
I;"""
18
~ 16
17
] 14
.~ 12
.-
~
[Z L..----- B-40
~ 10
~ 8
§ 6
CJ
JJ 4
"'C
2
V
l / B-20
V
o0
V
5 10
Y
V
~
V
V
L--- ~
~
tB-80
20 30 40 50 60 70 80 90
Times Normal Primary Current
100 110
Figure 2.9 Typical overcurrent ratio curves for a
T-class current transformer [5].
1000
~
wl::J 600-5 500-5
100
450-5 400-5
:,.
~
1/
oj
bD
....~
100"'"
/
~
~
300-5
1I~~
10
V~ V V~
--
~
I
I
CJ
><
~
~
"'C
~
0
CJ
1
//1
VII
WVlI 1I
1
(1)
I
v
IIIJ
/
/
7
17
)11
.1
/~~
.001
VI
~
/
J
V) /1/
.01
50-5
I
II
1I
777
o:
250-5
.... 200-5
150-5
I- 100-5
VI,,-
/
I
V
Typical Excitation Curve
Type BYM Bushing CT
Ratio 600-5, 60 Hz
.1
1
Secondary Exciting Current, L
10
100
Figure 2.10 Excitation curves for a multiratio bushing CT with an ANSI accuracy classification of CIOO [4].
ondary voltages to the current transformer with the primary circuit open, and give approximate
exciting current requirements for the CT for a given secondary voltage.
These curves can be used very simply to determine if the CT becomes saturated at
any given fault current. From (2.1), given the fault current and CT ratio, one can determine
the secondary voltage. From Figure 2.8, for the computed voltage, one can readily see if
the operating point is in the saturated region without making any further computation. This
method, including several examples, is discussed further in [4].
2.4.1.3 The Formula Method. An excellent method estimating the CT performance
is based on a knowledge of CT design principles. Table 2.1 shows the relationship between
the standard secondary burden of the C Class of current transformers and the rated secondary
27
Section 2.4 • Instrument Transformers
voltage. The rated voltage is based on voltage the CT will support across a standard burden
with 20 times rated current without exceeding 10% ratio correction.
TABLE 2.1 Standard Burden and Rated Voltage
of C Class CT's
C Class
Standard ZB (1)
Rated Voltage (2)
CIOO
IQ
100V
C200
2Q
200 V
C400
4Q
400 V
C800
8Q
800 V
(1) Assumed impedance angle of 60°
(2) Computed as 20 x 5A secondary current = A
The secondary voltage is a function of the CT secondary fault current 1F and the total
secondary burden Z B. We may write this voltage as
d
N ¢
v
(2.2)
dt
where N is the number of secondary turns and ¢ is the core flux in webers. Rearranging, we
compute the total flux in terms of the flux density as
==
v
N¢ =NBA
=
l'
vdt
(2.3)
For a fully offset voltage this becomes
N¢ = NBA =
= ZBi F
l' ZBiF(e~R'/L
-
[~(l e~R'/L) -
- coswt) dt
(2.4)
Sinwt]
Using the maximum value of the expression in square brackets, we write
NBAw
= ZBi F
(~ +
1)
(2.5)
Now, the secondary voltage rating of the CT is the voltage that the C'l' will support across a
standard burden with 20 times rated current, without exceeding a 10% ratio error. Thus, we
can write
(2.6)
where the burden is in per unit based on the standard CT burden and the fault current is in
per unit based on the CT rated current. Since we use an extreme value of the quantity in
parentheses, this will yield a conservatively small value of the maximum tolerable secondary
burden [6].
For example, for a transmission line with XIR of 12 and a maximum fault current of
four times rated current of a C800 CT, saturation will be avoided when ZB is less than 0.38
per unit of the standard 8 ohm burden, or about 3 ohms.
28
Chapter 2 • Protection Measurements and Controls
2.4.1.4 The Simulation Method. The ANSI accuracy charts, such as Figures 2.8 and
2.9, do not provide an accurate insight as to the waveform distortion that occurs when a
large primary current drives the current transformer into saturation. This problem has been
addressed and results published to show the type of distortion that may occur, especially
from fully offset primary currents of large magnitude [7], [8]. These publications show that
substantial waveform distortion is likely with high primary currents, especially if the current
is fully offset. A computer simulation has been prepared to permit the engineer to examine
any case of interest [8].
EXAMPLE 2.1
An example of a current transformer simulation is to be run for a current transformer of the C400 accuracy
class and with 40,000 amperes rms primary current, fully offset. Specifications for the current transformer
are shown in Table 2.2.
TABLE 2.2
Calculation
Data for C400 Current Transformer
CTratio
15015
CT relaying accuracy class
C400
Core cross-section area
43.1 in. 2
Length of magnetic path
24 in.
Secondary winding resistance
0.10
Secondary burden
0.1 +j on
CT secondary cable resistance
0.10
Frequency
60Hz
Primary current
40,000 A rms
Incident angle
0 0 (fully offset)
Primary current time constant
0.1 sec
Solution
The results of the computer simulation are shown in Figure 2.11, where the primary current is fully
offset with a typical decrement time constant. 2 The secondary current has an initial high pulse that
persists for less than 4 milliseconds in each half cycle. The performance of conventional overcurrent
relays is not specified when confronted with such currents. The relay will be affected by saturation in the
armature circuit and will have eddy currents induced due to the fast current rise. Note that this example
is determined for a CT that is operating at over 266 times its rating, but such a condition can occur in
power systems, depending on the availability of fault currents of high magnitude. The simulation method
is flexible since any transformer operating under any specified condition can be studied.
•
Since the performance of relays under the conditions described in the example are not
predictable, laboratory testing of the relay is advised to determine the relay behavior [8].
2.4.2 Instrument Transformer Types and Connections
Instrument transformers are available in a number of types and can be connected in a
number of different ways to provide the required relay quantities.
2.4.2.1 Current Transformers. Current transformers are available primarily in two
types: bushing CT's and wound CT's. Bushing CT's are usually less expensive than wound
2The author is indebted to W. C. Kotheimer of Kotheimer Associates for information regarding the saturation
of current transformers and for the plot data for Figure 2.11.
29
Secti on 2.4 • Instru ment Tran sform ers
120
~
.S 80
....r:::
......
~
40
::l
o
...>.Ol
S
.;:;
0..
0
-40
C400
2
0
3
4
5
7
6
8
9
10
Ti me in cycles
~
.S
....r:::
......
::l
~
()
Q
20 j ......
10 0
Ol
"0
r::: -10
0
'"
en
l Il
'-\ :
-
~
...
C400
-20
o
~
; ~
\1}j})\
~i · ~ ~
.
······__·(········i--·······;.........
..
~
.. ..
:
:
. ..,
,. _,
I
:
I
I
I
I
1
2
3
4
....
I
56
J
< •..
:
I
:
I
I
7
8
9
10
Tim e in cycles
Figure 2.11 Example ofCT secondary saturation due to large. fully offset primary curren\.
CT's, but they have lower accura cy. The y are often used for relaying because of their favorable
cost and because their accuracy is often adequate for relay applications. Moreover, bushin g
CT's are convenientl y located in the bushing s of transformers and circuit breakers. and therefore
take up no appre ciable space in the substation.
Bushing CT's are designed with a core encircling an insulating bushing. through which
the primary current lead of the bushing passes. Thi s means that the diamet er of the core is
relati vely large , giving a large mean magnetic path length compared to other types. The bushing
CT also has only one primary turn. namely, the metallic connection through the center of the
bushing . To compensate for the long path length and minimum primary tum conditi on, the
cross-sectional area of iron is increased . Thi s has the advantag e for relaying that the bushing
CT tends to be more acc urate than wound CT's at large multiples of secondary current rating .
The bushing CT, howe ver, is less accurate at low current s becau se of its large exciting current.
Thi s makes the bushing CT a poor choice for applic ations. such as meterin g, which requir e
good accuracy at norm al currents.
Current tran sformers are labeled with termin al markings to ensure correct polarity of a
given connection. The markin gs label the primary wind ing H and the secondary windin g X.
each with appropriate subscripts, as shown in Figure 2. 12. The usual practic e is to indicate
Figure 2.12 Polarity convention for current transformers [91.
30
Chapter 2 • Protection Measurements and Controls
polarity by dots, as shown in the two right-hand illustrations in Figure 2.12. Polarity marks are
essential where two or more current transformers are connected together so that the resulting
current definition can be clearly determined. For the bushing CT on the right in Figure 2.12,
the polarity designation can be omitted since the primary current is, by definition, assumed to
be flowing toward the breaker from the system.
Figure 2.13 shows a wye connection of current transformers, where the phasor primary
and secondary currents in each phase are exactly in phase, but differ by the magnitude of the
turns ratio.
_ ..._ ............._ . .
t,
~
a
Ib
~b
.i:
-...-. . . . ..----.. .-. . ----c
~-
Phase
Relays
Figure 2.13 Wye connection of current transformers [9].
The delta connection of CT's can be made in two ways, and these are shown in Figure 2.14, together with the resulting phasor diagrams for each connection. It can be easily
shown that the output secondary currents for these connections contain no zero sequence
component. Note that delta connection B is the reverse of connection A.
The delta connection of current transformers is important for distance relaying". The
subject is explored in Chapter 11.
2.4.2.2 Voltage (Potential) Transformers. Two types of voltage measuring devices
are used in protective relaying: These are the instrument potential transformer, which is a
two-winding transformer, and the capacitance potential device or coupling capacitor voltage
transformer (CCVT), which is a capacitive voltage divider.
The wound potential transformer is much like a conventional transformer except that it
is designed for a small constant load and hence cooling is not as important as accuracy.
The capacitance potential devices in common use are of two types: the coupling-capacitor
device and the bushing device. These are shown in Figure 2.15. The coupling capacitor device
is a series stack of capacitors with the secondary tap taken from the last unit, which is called
the auxiliary capacitor. Bushing voltage dividers are constructed from capacitance bushings,
where a particular level is tapped as a secondary voltage.
The equivalent circuit of a capacitance potential device is shown in Figure 2.16. The
equivalent reactance of this circuit is defined by the equation
XCIXC2
XL = - - - XCI + X C2
(2.7)
This reactance is adjusted to make the applied voltage and the tapped voltage in phase, in
which case the device is called a resonant potential device. Since the bottom capacitor is much
larger than the top capacitor
XC2
«
XCI
(2.8)
Section 2.4 • Instrument Transformers
31
_ _............
~Ia
_ _................__~ I a
.....................__~Ib
-............-t-t...._ _
:!'E-- I b
t,
..................
Ie -
~
t,>
I
--~
t, -
a
Ib
t,
- ....................
_--~
-
t,
Ia - I b
i,
..
Ie
I
b
Ib
-
t,
I a - i,
Ib
Figure 2.14 Delta connection of current transformers and the phasor diagrams for balanced
three-phase currents [9).
- - - . . - - - - High-voltage
conductor
Bushing
Bushing
Capacity
units
Capacitance
Tap Shield
Bushing
Ground
Shield
I J
J
I
J
I
J \
J l
"
~t·-l }
--3
~Tap
J
\
I
I J
\ I
I I
I (
I I
Aux. capacitor
Figure 2.15 Capacitor potential devices [9], [10].
32
Chapter 2 • Protection Measurements and Controls
R
Figure 2.16 Equivalent circuit of a capacitor potential device [9].
which means that, practically
(2.9)
Potential transformers (or capacitance devices) are connected Y-Y, ~-~, y-~, or ~-Y, as
required for particular applications. In many applications the open delta connection is used so
that one potential device can be saved and the three-phase voltages can still be provided.
CCVT's are usually designed to reduce the transmission voltage to a safe metering level
by a capacitive voltage divider, although a magnetic core transformer may be needed to further
reduce the voltage to relay voltages, usually 67 volts line-to-neutral (115 Y line-to-line).
2.4.2.3 OpticalCurrentand Voltage Transducers. The foregoing discussion indicates
that there are problems associated with the accurate acquisition of system currents and voltages
due to faulted system conditions. This is especially a problem in capturing the transient
currents and voltages that are required to correctly analyze the faulted system conditions.
Current transformers tend to saturate, and voltage transformers, especially CCYT's, suffer
from transient errors, especially for faults causing significant voltage collapse [10-16].
A new type of current and voltage transducer has been introduced, which solves many
of the problems cited for ferromagnetic transducers. The principle of optical devices is based
on a measurement of the magnetic field in the vicinity of the current-carrying conductor. The
measurement is based on optical modulation and demodulation of the Faraday effect [11],
[12]. Using this technique it is possible, in principle, to measure even de current. Some of the
advantages of this new method are the following:
1. The signal obtained from the current carrying conductor is transmitted to electronic
processing equipment using fiber optic cables, which have the advantage of electrical
insulation and rejection of electromagnetic induction noise.
2. The dynamic range of the optical devices are projected to be greatly superior to
electromagnetic transformers.
3. The transducers should be compact and lightweight devices.
A simplified view of this type of optical current transducer (OCT) implementation is
shown in Figure 2.17. The principal elements of the system are the sensor assembly, where
the field measurements in the vicinity of the conductors are made, the fiber-optic cable that
transmits the measured signals, and the signal processing unit, which consists of an optical
interface and a computer.
Several devices of this type have been introduced [13-18], and others are sure to follow.
All proposed systems use fiber optics to isoiate the grounded parts from the high-voltage parts
of the system, as shown in Figure 2.17.
Considerable effort has been concentrated in producing an optical current transducer
(OCT). These devices are not current transformers, but optical electronic measurement systems.
33
Sec tion 2.4 • Instrument Transformers
Sensor
Insulator
~High
Volt age
Support
Structure
Line
Fib er
Figure 2.17 Typical arrangement of an optical
current transducer 11 61 .
Ca ble " "
2::::~1:;=1---''''-
There are several different methods that can be used to design an OCT, and most of the methods
explored are not based on transform er prin ciples. The power level of the signal availabl e for
gro und-based processin g is weak, being typi call y in the microwatt range. Th is is in contras t to
the sig nal level of ordinary current transformers, which is at a level of several watts. The OCT
has severa l advantages over conventional CT's. Th e OCT is light in weight, being much lighter
than an oi l-filled CT of similar rating, which result s in savings in installation cos t. Optica l
sys tems are imm une from electrical noise. Th ey provide safe ty adva ntages due to the natural
insulating qual ity of the optica l transmission fibers. Th e optical systems are also less likely to
fail catastrophically than conventiona l curren t transformers.
Opti cal curre nt measurements have been investigated since the late I 960 s, but were
not extensive ly developed until the late 1970s and ear ly 1980s. As a result of extensive
research, several different approac hes have been explored. Most of the systems under active
development employ some techn ique to measure the magnet ic field associated with the curre nt
in the conductor of interest. Thi s is an application of Ampere 's law, which ca n be writte n as
1=
f
H « dl
(2. 10)
where I is the curre nt, H is the magneti c field intensity, and dl is the clos ed path of integra tion.
Th e path of integrati on is optional and is accomplished in diffe rent ways by the developers.
using circular, square, or other path configura tions. Other methods can be used , but the
conversion from magnetic to optical signals is currently the most common. Th is type of
conversion is usually refe rred to as the "Faraday effect" or the "mag neto-optic effect" in
the techn ical liter ature. In practice, transparent glasses or crys tals are used to construct the
Faraday effect devices. Th ese glasses have the property that the value of the refractive index
depend s on the direct ion of propagation and the polarization of the light and the refract ive
index has different values for two mutu ally orthogo nal polarization s of the light wave . Th e
plane of polarizatio n is proport ion al to the mag netic field in the mater ial and is measured by
the rotation of the plane of polari zation using various methods.
The physical devices that have been developed ca n be clas sified into five different types
r18], as show n in Figure 2. 18. Type I uses an ordinary current transformer with an added
insulated optica l transducer added. Type 2 uses a magnetic circuit aro und the conductor and
measures the field inside the magnetic co re optica lly in an air gap. Type 3 uses an optical
path in a block of optica lly active material. with the light path enclosi ng the curre nt in the
con ductor exac tly once, which is an optica l implementation of a conventional CT. Type 4 uses
34
Chapter 2 • Protection Measurements and Controls
an optical path inside a fiber that is wound around the conductor any number of times. Type
5 measures the magnetic field at a point near the conductor, and is therefore not considered a
true current transducer. The devices shown in Figure 2.18 represent the state of the art in the
mid-1990s. Additional transducers are anticipated as the technology matures and refinements
are implemented by developers.
Current
Transformer
Sensing
Optics
Magnetic
Core
~----....../
Output
Fiber
Input Output
Fiber Fiber
(3)
(2)
Input
Fiber
(4)
Output
Fiber
(5)
Figure 2.18 Types of optical current transducers [181. (I) Conventional CT with optical
readout. (2) Magnetic concentrator with optical measurement. (3) OCT using
bulk optics . (4) Fiber optics based current measurement. (5) Witness sensor.
2.5 RELAY CONTROL CONFIGURATIONS
As a final topic .on relay control, we consider the many ways in which system data can be
monitored and transmitted to relays . Consider the relay connections in Figure 2.19, which
might be considered the maximum practical redundancy in relay connections. Note that there
are two independent relay systems, each of which could contain several relays to detect phase
and ground faults on the protected line section.
This system is made very reliable by the use of completely independent systems for
•
•
•
•
de power supply (batteries)
potential supply to each relay system
current monitoring for each relay system
dual trip coils in the circuit breaker
35
Section 2.5 • Relay Control Configurations
Transmission line
Figure 2.19 Transmission line protection with
redundant relay systems and independent system
data gathering systems [4].
VT2
Battery #2 +
Protected line section
Dual communications systems to the remote end of the line can also be provided. The
two systems are designated the "primary" and the "backup" systems, although they could,
in fact, be identical systems. In the illustration, the secondary system is "supervised" by an
overcurrent device (50) so that it will function only when an overcurrent is detected. This
supervision is optional, but it may be used to ensure that the primary relay operates first, for
example, where the primary system has superior selectivity. The overcurrent device (50) is
often connected in series with transmission line distance relays to prevent false tripping on
loss of potential due to blown fuses or other causes that result in loss of voltage measurement
to the relay.
The redundancy in Figure 2.19 is not uncommon, except for the redundant battery, which
is seldom specified. Note that all system functions are duplicated except the circuit breaker.
It would be possible to place redundant circuit breakers in series and have them controlled by
independent relays. This would be very costly, and would probably not even be considered
except for a circuit that is considered very important for some reason.
Figure 2.20 shows control configurations that are commonly used in power system protection. Part (1) has redundancy only in the relays and the two relay systems share the same
battery and the same instrument transformers.
In part (2), the system is made ITIOre reliable by duplicating the instrument transformers,
giving each relay its own independent supply. This leaves the circuit breaker trip coil and
breaker mechanism as the most vulnerable to failure of the protective system. Part (3) of
Figure 2.20 uses duplicate trip coils and has each relay connected to its own trip coil. Since
the added trip coil can be obtained at quite a reasonable cost, this is often considered to be
prudent, especially for the higher voltage circuits that carry large amounts of power. On these
circuits, failure to properly clear a fault can have very high cost, hence greater redundancy is
readily justified. Part (4) of Figure 2.20 uses redundancy in all subsystems except the circuit
breaker mechanism, which would be very expensive to duplicate. This arrangement would be
used at stations where high reliability is very important.
Obviously, other control configurations can be devised. It is not likely that a utility
would use the same configuration for all applications, since the protected circuits are not
equally important to the integrity of the entire system. Generally, the high voltage bulk power
transmission lines will be protected by highly redundant protective systems, since these lines
carry large amounts of power and high availability is essential.
36
Chapter 2 • Protection Measurements and Controls
(1)
(2)
(3)
(4)
Figure 2.20 Block diagram of typical control configurations. (1) Redundant relays. (2)
Redundant instrument transforms and relays. (3) Redundant instrument transforms, relays, and trip coils. (4) Redundant instrument transforms, relays, trip
coils, and batteries.
2.6 OPTICAL COMMUNICATIONS
One of the most difficult technologies in power system protection is that of communications.
In many types of protection, control, and measurement, the information must be transmitted
from one location to another, where the data transmitter and receiver may be a great distance
apart. Moreover, both the sending and receiving end of the transmission are often at highvoltage switching stations, where power frequency electromagnetic interference (EMI), radio
frequency interference (RFI), switching transients, and even lightning are a part of the operating
environment. These environmental problems have plagued protection engineers for years and
have often been the source of numerous false trips of transmission lines and other protected components. This problem has become even more difficult with the advent ofdigital systems, which
generate tremendous amounts of data that must be transmitted without error to remote points.
Fortunately, a solution to these communications problems has emerged in the form of
an optical waveguide or optical fiber, in which light propagates along the fiber by total internal
reflection. The optical fiber consists of a core material that has a refractive index higher than
37
Section 2.6 • Optical Communications
that of the cladding material surrounding the fiber. Transmission with this type of optical
waveguide has many advantages over wire communications and makes it possible to transmit
large volumes of data from point to point with high reliability and low error rate. The high
data rate is possible because of the high bandwidth and low loss of the fiber. Moreover, this
medium is immune to outside electromagnetic fields, which pose such a difficult problem for
wire communications. especially in the environment of high-voltage substations.
There are three basic types of light guides that are usually identified according to fiber
design :
(a) Multimode, stepped refractive index profile
(b) Multimode. graded index
(c) Single mode, stepped index
The basic differences in the three modes are illustrated in Figure 2.21. Multimode,
stepped refractive index profile fibers, (a) in Figure 2.21, are often used for image transmission
and short distance data transmission . The number of rays or modes of light that can be guided
by this type of fiber depend on the core size and on the difference in refractive index between
the core and the cladding. A transmitted pulse flattens out as it travels down the fiber because
the higher angle modes have a greater distance to travel than the low angle modes. This limits
the data transmission rate and the distance because it determines how close the pulses can be
spaced without creating overlap at the receiving end.
Cross
Section
Ind ex
P rofile
Light Path
Input
Pul se
Output
Pul se
©
o
(a)
f\
(b )
@
(e)
Figure 2.21 Types of optical fiber transmission .
In the graded index multi mode fiber, (h) in Figure 2.21, the refractive index decreases
with radial distance from the center. This tends to minimize pulse broadening due to the mode
dispersion since the light rays travel more slowly near the center of the fiber. This type of fiber
is used for medium distance, intermediate rate transmission.
High rate transmission systems use the single mode fiber, (c) in Figure 2.21. These
fibers have low refractive index difference and a small core size, which tends to eliminate
pulse dispersion since only one mode is transmitted. This type of fiber is useful for long
distance, high data rate transmission systems.
The wavelength of light transmitted is a critical parameter in determining the attenuation
ofthe signal. Experience has shown that the lowest attenuation occurs with infrared frequencies
of 850, 1300, and 1500 nanometers (nm) . The 850 nm wavelength , commonly used for utility
applications, is available from light-emitting diodes (LED) or laser diodes (LD) . Use of the
higher frequencies is spreading rapidly, however.
38
Chapter 2 • Protection Measurements and Controls
Splicing of fiber cables has proven to be rather easy in spite of the small size of the fibers.
Almost lossless splices may be fabricated in the field and have proven to be quite reliable. A
number of splicing techniques have been developed, some of which are mechanical while
others depend on fusing or welding the glass ends together. Splicing is important since some
applications link stations that are many kilometers apart. The physical arrangement employs
transmission static wires that incorporate fiber-optic cables in several optional configurations.
Testing has also been performed in constructing high-voltage phase conductors that incorporate
fiber-optic strands for communications [19].
Utility applications for fiber-optic data transmission are growing rapidly. The need for
data acquisition and communications for supervision, control, and protection are the primary
applications. In the past, these needs were met using a variety of communications media,
such as microwave, power line carrier, and hard-wired circuits. Optical systems, however,
offer an almost ideal replacement for these media due to three major advantages: immunity to
high electromagnetic fields, wide bandwidth, and the nonconducting characteristic of the fiber
cables. The fiber systems offer excellent tolerance to vibration, no cross-talk with adjacent
cables, immunity to EMI and RFI, no spark or fire hazard, no short-circuit loading, no ringing
or echoes, and no contact discontinuity [19]. Moreover, test installations show that the cost is
often competitive.
One application that is attractive is interstation communications, control, and protection.
Interstation links are typically from a few hundred meters to a few tens of kilometers. Repeater
stations are required at about 15 km intervals, but this is a function of the attenuation and will
improve with future development.
Intrastation applications are also being tested with excellent results. Here, the fiber-optic
alternative is attractive because of its freedom from interference problems and because of the
insulation characteristics of the fiber cables themselves. Signals from transducers and circuit
breakers are converted to digital form and transmitted to a control room, where they are fed to
microcomputers for processing. These microcomputers work with low-voltage input signals
and would be damaged by transients. Here, the use of fiber cables is an ideal solution, since
the cable isolates the sensitive equipment from the high-voltage equipment and shields the
transmitted data from any type of outside interference. Applications in generating stations are
also growing rapidly, due to the distributed controls now being used in power plants. Here, fiber
optics eliminates such problems as ground loops and interference, and also requires much less
space than the older equipment. Fiber-optic systems are even being placed inside light-water
nuclear reactors to gather data on the reactor operating conditions.
The actual measurement of power system parameters is critical to any communications
and control system. The measurement of voltage, current, temperature, pressure, and other
physical parameters is the heart of any control and protection system. The potential of optical
devices as sensors provides important new opportunities, as noted in Section 2.4.2.3. The ideal
sensor for utility applications should have the following characteristics [19]:
• Nonmagnetic-impervious to external influence
• Passive-self-powered
• Fully dielectric-no need for insulating support structures
• Accurate--capable of precision measurement
New optics-based sensors promise benefits in all of these areas. One type, the "Pockels"
voltage sensor, is promising. It is based on a characteristic of lithium niobate (LiNb0 3 )
crystal. When exposed to an electric field, the index of refraction of one of its axes changes in
39
References
proportion to the strength of the field, a characteristic called birefringence. The shift of axis
can be analyzed by passing a beam of polarized light through the crystal, permitting accurate
calculation of the voltage producing the field. Present sensors are accurate to 0.50/0, but 0.1 %
should be possible [20]. These devices do not need to contact the high-voltage conductor,
but can be located a few feet off the ground under the substation bus structure, where the bus
electric field can be sensed.
Optical current sensors use a Faraday glass material that rotates its polarization under
the influence of a magnetic field. Several such sensors are under development. Sensors for
temperature and other physical quantities are also under development.
The development of optical sensors, together with optical data transmission systems,
promise to provide new methods of data acquisition and transmission that will eliminate problems that have always been difficult for the protection engineer. Future protection and control
systems should have the benefit of cleaner signals, uncorrupted by outside interference. Moreover, the optical concept meshes perfectly with the low-voltage ratings of digital devices that
will be the heart of future protective systems.
REFERENCES
[1] IEEE Std 315-1975 (ANSI Y32.2-1975), "IEEE Graphic Symbols for Electrical and Electronics
Diagrams," IEEE, New York, 1975.
[2] ANSIJASME Y 1.1-1972, "Abbreviations, For Use on Drawings and in Text," American Society of
Mechanical Engineers, New York, 1972.
[3] ANSIIIEEE C37 .2-1991, "IEEE Standard Electrical Power System Device Function Numbers,"
IEEE, New York, 1991.
[4] Blackburn, J. L., Ed., Applied Protective Relaying, Westinghouse Electric Corp., Newark, NJ, 1976.
[5] ANSI Std C57 .13-1993, "IEEE Standard Requirements for Instrument Transformers," IEEE, New
York, 1993.
[6J Zocholl, Stanley E., Jeff Roberts, and Gabriel Benmouyal, "Selecting CTs to Optimize Relay
Performance," a paper presented at the 23rd Annual Western Protective Relay Conference, Spokane,
Washington, October 15-17, 1996.
[7] IEEE Power System Relaying Committee, Transient Response of Current Transformers, IEEE
Publication 76 CH 1130-4 PWR, IEEE, New York, January 1976.
[8] Garrett, R., W. C. Kotheimer, and S. E. Zocholl, "Computer Simulation of Current Transformers and
Relays for Performance Analysis," a paper presented at the 14th Annual Western Relay Conference,
Spokane, Washington, October 20-23, 1987.
[9] Mason, C. Russell, The Art and Science of Protective Relaying, John Wiley & Sons, New York,
1956.
[10] Phadke, Arun G. and James S. Thorp, Computer Relaying for Power Systents, John Wiley & Sons,
Inc., New York, 1988
[11] Poljac, M. and N. Kolibas, "Computation of Current Transformer Transient Performance;' paper
88 WM 046-5, presented at the IEEE PES Winter Meeting, New York, 1988.
[12] Zocholl, S. E., W. C. Kotheimer, and F. Y. Tajaddodi, "An Analytical Approach to the Application
of Current Transformers for Protective Relaying," a paper presented at the 15th Annual Western
Relay Conference, Spokane, October 1988.
[13] Saito, S., J. Hamasaki, Y. Fujii, K. Yokoyama, and Y. Ohno, "Development of the Laser Current Transformer for Extra-High-Voltage Power Transmission Lines," IEEE J. Quant. Elec., QE-3,
November 1967, pp. 589-597.
[141 Rogers, A. J., "Method for the Simultaneous Measurement of Current and Voltage on High-voltage
Lines using Optical Techniques," Proc. lEE, 123, October 1976, pp. 957-960.
40
Chapter 2 • Protection Measurements and Controls
[15] Sawa, T., K. Kurosawa, T. Kaminishi, and T. Yokota, "Development of Optical Instrument Transformers," paper 89 TO 380..7 PWRO, presented at the IEEE PES 1989 Transmission and Distribution
Conference, April 2-7, 1989, New Orleans.
[16] Ulmer, Edward A., Jr., "A High-Accuracy Optical Current Transducer for Electric Power Systems," paper 89 TD 382-3 PWRD, presented at the IEEE PES 1989 Transmission and Distribution
Conference, April 2-7, 1989, New Orleans.
[17] Aikawa, Eiya, Masami Watanabe, Hisamitsu Takahashi, and Mitsumasa Imataki, "Development
of New Concept Optical Zero-Sequence CurrentIVoltage Transducers for Distribution Systems,"
IEEE Trans. PWRD (6), January 1991, pp. 414-420.
[18] IEEE Committee Report, "Optical Current Transducers for Power Systems: A Review," IEEE paper
94 WM 241-0 PWRD, presented at the IEEE PES Winter Meeting, New York, January 30-February
3, 1994.
[19] Nagel, Suzanne R., "Optical Fibers," McGraw-Hill Encyclopedia of Science and Technology, 5th
Ed., McGraw-Hill Book Co., New York, 1982.
[20] Hayes, William C., "Fiber Optics: The future is now," Electrical World, February 1984, pp. 51-59.
PROBLEMS
2.1 The 90 degree connection of system ac voltages and currents to a set of phase relays, as
shown in Figure 2.3, is sometimes altered by inserting a resistor R in series with each of the
potential coils of the relay. This has the effect of making the relay voltage lead the line-to-line
voltage applied to the relay and brings the relay voltage and current more nearly in phase.
Sketch this connection and its phasor diagram.
2.2 Sketch an ac relay connection similar to the 90 degree connection of Figure 2.3, but one that
results in a 30 degree phase relationship between the relay voltage and current at unity power
factor.
2.3 What is meant by the term electrically trip free? What is meant by the term mechanically
trip free?
2.4 Distinguish between dropout and reset of a relay. Consult the definitions of Appendix A.
2.5 Calculate the secondary phase and sequence currents flowing in the phase relays and in the
ground relay for the wye connection of Figure 2.13 for the following fault conditions:
(a) A three-phase fault
(b) A one-line-to-ground fault
(c) A line-to-line fault
2.6 Calculate the secondary phase currents for the two delta connections of Figure 2.14 for the
.
following conditions:
(a) A three-phase fault
(b) A one-line-to-ground fault
(c) A line-to-line fault
2.7 Devise a current transformer connection scheme that permits only positive sequence currents
in the phase relays and only zero sequence currents in the ground relay.
2.8 Derive (2.1).
2.9 Estimate the primary current that will just saturate a current transformer of high permeability
silicon steel, with a cross section of 0.00 17 square meters. The total secondary burden is 2.7
ohms, and the CT ratio is 2000:5.
2.10 Consider the application of a bushing current transformer with a 1500:5 turns ratio. This
CT is to be used in a circuit with a maximum fault current of 25,000 A. The relay burden is
2.0 ohms, including the secondary leakage and the lead impedance. The current transformer
iron circuit has a cross section of 0.002 square meters, and it saturates at 1.5 Tesla. Use the
formula method to find out if the current transformer will saturate under the given conditions.
41
Problems
2.11 Repeat problem 2.10 using a CT ratio of 1000:5.
2.12 A radial circuit is protected by overcurrent relays that should be adjusted to operate for a
fault at the extreme end of the radial line, giving a fault current of 60 A. The circuit breaker
has multiple ratio bushing CT's, with ratios as shown in Figure 2.8. The relay has available
tap settings by which the minimum relay pickup current may be adjusted. However, each tap
setting of the relay results in a different relay burden, which we approximate by the formula
ZB == 10/tap
Taps available are given as 3, 6, 9, and 12 A, where the tap value is taken as the minimum
pickup current of the relay. Use the excitation curves of Figure 2.8 to determine a suitable
tap and CT ratio, assuming we wish to keep the excitation current to less than 3% of the total
primary current.
2.13 Figure P2.13 shows the bus connection at Station X and the lines leading to adjacent stations
R, S, T, U, V, and W. Sketch the voltage and current transformer connections for the protection
of line XS.
Figure P2.13 Bus arrangement of Station X.
2.14 In computing the total impedance of a given fault on an overhead line, it is often important
to estimate the resistance of the arcing fault. Warrington [21] gives the following formula
for the arc resistance.
8750(s
Rare
where
==
+ ut)
1 1.4
== arc resistance, ohms
s == conductor spacing, ft
u == wind velocity, mile/hr
I == fault current, Arms
t == time, sec
Rare
Suppose that the following impedance values are given:
Zs == 0 + j25Q
Source:
Line:
ZL == 11 + j22Q
(a) Determine the fault impedance, both with and without arc resistance, when the line is
radial from the source.
(b) Repeat (a) for a fault at the sending end of the line.
(c) Plot the results of (a) and (b) in the complex R-X plane.