GE 12CEYG51B(-)D User manual

INSTRUCTIONS
GEK—
34169
DIRECTIO1AL DISTANCE
RELAY
1YPE
CEY
Insert
Booklet—
GEK-26423
MODEL
12CEYG51B(-)D
INTRODUCTION
This
instruction
book
along
with
the
LCEYG51A(-)D relay
Instruction
Book,
form
the instructions for
the
12CEYGS1B(-)D
re 1
ay.
DESCRIPTiON
The 12CEYG51A(-)D
relay
except
for
the
removal
of
the
target/seal-in
unit
and
its
circuitry.
Rfu,’
to
figure
1
for the
12CEYG51B(-)D internal
connecLion
dgram.
Since
the
relay contacts
are
no
longer
protecect
by
a
ei
n
unit,
the
contacts
must
never
inte’rut
curren
or
carv
trip
current
for
more
than
16 milliseconds.
These
instructions
do
not
purport
to
cover
all
details
or variations
in
equipmtnt
nor to provide
for
every
possible
contingency
to be
met in
connection
with
installation,
operation
or
maintenance.
Should
further
information
be
desired
or should
particular
proble.s
arise
which
are
not
covered
sufficiently for the
purchaser’s
purposes,
the
matter
should
be
referred
to the
General
Electric
Company.
POWER
SYSTEMS
MANAGEMENT
DEPARTMENT
GENERALS ELECTRIC
J
PUIIADLLPNIA.
PA.

GEK-34169
cV>
Bb>
vi2
0
M3
A
1
57
M1TOP
UNIT
M2=MIDDLE
UNIT
SHORT
FINGER
M3=BOTTOM
UNIT
FIG.
1
(0246A3351-O)
Internal
Connection
Diagram For
The
CEYG51B(-)D
Relay
B
Ml
A
1
4
6
8
10
GENEtAL ELECTRIC
COMPANY,
PHILADELPHIA,
PA

GEK-26423D
INSTRUCTIONS
GROUND
DISTANCE
RELAY
TYPE
CEYG51A
GE Protection
and
Control
205
Great
Valley
Parkway
Malvern,
PA
19355-1337

GEK-26423
CONT
E
NT
S
PAGE
iNTRODUCTION
3
APPLICATION
3
RATINGS
4
Contacts
4
OPERATING
PRINCIPLES
5
CHARACTERISTICS
Pickup
6
Operating
Time
6
Burden
6
CALCULATION
OF SETTINGS
7
CONSTRUCTION
9
RECEIVING,
HANDLING
AND
STORAGE
9
ACCEPTANCE
TESTS
10
Visual
Inspection
10
Mechanical
Inspection
10
Electrical
Tests
10
INSTALLATION
PROCEDURE
11
Relay
Settings
11
Mechanical
Checks
11
Electrical
Checks
11
PORTABLE
TEST
EQUIPMENT
11
SERVICING
14
Restraint
Circuit
Angle
Adjustment
15
Directional
Characteristic
15
Maximum
Torque
Angle
15
Pickup
15
Clutch
Adjustment
15
RENEWAL
PARTS
16
APPENDIX
I
MINIMUM
PERMISSIBLE
REACH
SETTING
FOR
THE
CEYG51A
17
No
Zero
Sequence
Current
Compensation
17
With
Zero
Sequence
Current
Compensation
18
APPENDIX
II
MAXIMUM
PERMISSIBLE
REACH
SETTING
FOR
THE
CEYGS1A
18
No
Zero
Sequence
Current
Compensation
18
APPENDIX
III
MAXIMUM
PERMISSIBLE
REACH
SETTING
FOR
THE
CEYG51A
20
With
Zero
Sequence
Current
Compensation
20
2

GEK-2
6423
GROUND
DISTANCE
RELAY
CEYG51A
RELAY
INTRODUCTION
The
CEYGSIA
is a
three
phase,
high
speed,
single
zone,
inho
type,
directional
distance
ground
relay.
It
consists
of
three single-phase
units
in one
L2—D
case
with
facilities
for
testing
one unit
at a time.
One
target
and
seal-in
unit provides
indication
of
operation for
all
three
distance
units.
The
transient
over
reach characteristic
of the
CEYG51A
relay
has
not been
limited
to
the point
where
it is
suitable
for
use
as
a first-zone
relay.
The relay
was
specifically
designed
for use
as an
overreaching
device
in directional
comparison
and transferred
tripping
schemes.
Figure
3
shows
the
internal
connections.
APPLICAT
ION
The
CEYGS1A
ground
mho
relay is
applied
as the
primary
ground
relay
in
directional
comparison
and per
missive
overreaching
transferred
tripping
schemes,
employing
separate
primary
and
separate
backup
protec
tion.
The
ground
rnho
units
of
the CEYG51A
relay are
specifically
designed
to
detect
single
phase
to
ground
faults.
To this
end
they
are supplied
with quadrature
voltage
polarization.
Thus,
the polarizing
voltage
will
be quite
high
and
the
relay
will
have
a
high operating
torque
level
even
on very
close
in
line
to
ground
faults.
For
this reason, these
units
are not
provided
with
memory
action.
These
ground
mho units
will also
respond to
three
phase
faults.
If
this
is
objectionable,
the
relay
can be
made
unresponsive
to
any
faults
not
involving
ground
simply
by
adding
a non-directional
zero
sequence
fault
detector.
The ground
mho
units
are
provided with
separate
current
circuits
for
zero
sequence
current
compensa
tion.
A
tapped
auxiliary
current
transformer
is
used to
obtain
the
proper
ratio
of
compensation.
When
zero sequence
current
compensation
is
used,
the
ground
niho
unit has
essentially
the
same
reach on
single
phase
to
ground
faults
as
on three
phase
faults.
If zero
sequence compensation
is
NOT used,
the
ground
mho unit
roach
is
considerably
foreshortened
on
single
phase
to
ground
faults.
See
Appendix
I for
the
minimum
permissible
reach
settings
under both
conditions.
In directional
comparison schemes,
two
CEYG51A
relays
connected
back—to-back
are required
at
each
terminal.
These relays
operate
in
conjunction
with a
carrier
channel to
provide
high
speed
protection
against
all
single
phase
to
ground
faults
in
the protected
line section.
One relay
acts
to stop
carrier
and
trip for
internal
faults
while the
other
initiates
carrier
blocking
on
external
faults.
If
zero
sequence
current
compensation
is used
on
the carrier
stopping
and
tripping
units,
it
should
also
be
used
on
the
carrier
starting
units.
This
will
facilitate
the
unit
settings
and
insure
that
both
units
that
must
coordinate
will
be
operating
on
the
same
torque
level.
In
any event,
the
carrier
starting
unit
should
be
set as
sensitively
as
possible.
This will
tend
to
increase
security
since
the
presence
of
a
carrier
signal
will
block
tripping.
In
permissive overreaching
transferred
tripping
schemes,
one
CEYG5IA
relay
is
required
at
each
ter
minal.
It acts
as
a
combined
transferred
trip
initiating
and
a
permissive
relay for
ground
faults
in the
protected
line
section.
The
choice
of
whether
or
not
to
use
sequence
current
compensation
depends
upon
the
protected
line
length
and
system
conditions.
When
zero
sequence
current
compensation
is
NOT used,
the
ground
mho
unit
reach
required
may
be
about
2 to
3 times
the positive
sequence
impedance
of
the
line
in order
to
provide
the
proper coverage.
This then
tends
to
make
the ground
niho
unit
more
sensitive
to operation
on
load
con
ditions
or on
power
swings.
The use
of
zero
sequence
current
compensation
reduces
the
necessary
ground
mho
unit
reach
setting
to
approximately
1.2S
times the
positive
sequence
impedance
of the
line
and,
thus,
minimizes
its
response
to load
or
power
swings.
This
is true
provided
there is
little
or
no
mutual
im
pedance
present
from
a
parallel
line.
These
h?structlons
do not
purport
to cover
all
details
or variations
in
equipment
nor to
provide
for
evero
pass:nle
contingency
to be
met
an
connection
with
installation, operation
or maintenance.
Should
fartn-r
;nformation
be
desired
or
shouM particular problerrm
arise
which
are
not covcrci
suffic;enLlq for
tni
purchaser’s
r’Jrposes,
the
matter
should
be
referred
to the General
Electric
Company.
To
the extenL
reaured
the
;roducL-s
described
herein
meet
applicable
7’IS1,
IEEE
and
.VEM.4
standards;
ut not
sicn
assurance
s
7iven
w
th
respect
to local
codes
and
ordnan:esj,ecaue
ti?C5 car
greatly.

GLK-26423
Whether
or
not
zero
sequence
current
compensation
is
used,
the
ground
mho
units
may
be subject
to
in
ccrrect
operation
on
ground
faults
immediately
behind
the relay
terminals.
This will
be
dependent
upon
the
line
impedance
and
system
conditions.
It
may
he
necessary
to 1
unit the
mho
unit
reach
setting
in
order
to avoid
this false tripping.
Appendix
II
gives
the
liniiatations
of
the
mho
unit reach
setting
when
zero
sequence
current
compensation
is
NOT
used
Appendix
III
gives
the limitations
of
the
inho unit
reach
setting
when
zero
sequence
current
compensation
is used.
The
system
conditions
which
require
the
limi
tdtion
of
the
uho
unit
reach,
as
described
by
Appendices
Nand
111,
are rather
unusual.
They
occur
when
the
zero
sequence
current
contribution
over
the
line
to
a
Fault
behind
the
relay
is
larger
than
the
positive
sequence
current
contribution.
If
the
reach
of
the
unfaulted
phase
units
in
the non-trip
direction
is
an
application
limitation,
a
zero
soquence
directional
overcurrent
relay
(CFPG16A)
may
be
used
to
supervise
the
CEYG51
operation.
This
will
permit
tripping
only
when
the
fault
is in
the forward
direction.
The
external
connections
are
shown
in
Figure
4.
Since the
CEYG51A
is an
extended
range
relay
with
three
basic
minimum
reach
settings,
the
best overall
pcrforiance
will
be
obtained
if
the highest
basic
minimum
reach
tap setting
that
will
accommodate
the
de
sired
setting
is
used.
RATINGS
The
Type
CEYG51A
relays
covered
by
these
instructions
are available
with
potential
circuits
rated
for
operation
on
wye—wye
connected
potential
transformers
which
supply
secondary
voltage
of
120
volts
phase-
to-phase.
Current
coil
ratings
and
ohmic
ranges
are
as
tabulated
below:
BASIC
MIN.
RANGE
CONTIN.
ONE
SEC.
OHMIC
REACH
OHMIC
REACH
CURRENT
RATING
CUR.
RATING
(-N
OHMS)
(p-N
OHMS)
AMPERES
AMPERES
1/2/3
1
-
30
5
225
•
0.5/1.0/1.5
0.5
—
15
5
[
225
The
ohmic
reach
is
at
the
angle
of
maximum
torque
of
60
degrees
lag,
and
can be
adjusted
in
5
percent
steps
by
means
of
a
tapped
autotransformner.
It
will be
noted
that
three
basic
minimum
reach
settings
are
listed
for
the
mho units.
Selection
of
the
desired
basic
minimum
reach
is
made by
means
of
links
on
terminal
boards
located
on
rear
of
the
relay.
The
positions
of the
two
sets
of
links,
(for
each
M
unit),
each
identified
as A-B
determine the
minimum
ohmic
reach
setting
as
follows:
MINIMUM
OHMIC
REACH
SETTING
(OHM
PHASE-TO-NEUTRAL)
=
A
+
B
CONTACTS
The
main
circuit-closing
contacts
of
the
re1a
will close
and
carry
30
amperes
DC
momentarily
for
tripping
duty
at
control
voltages
of
250V
DC
or
less.
The
circuit
breaker
trip
coil
should,
however,
always
by
opened
by an
auxiliary
switch or
other
suitable
means.
If
the
tripping
current
exceeds
30
amperes,
a
tripping
relay
should
be
used.
The current
carrying
rating
of
the
main contacts
is
determined
by
the
tap
setting
of
the
seal—in
coil
as
shown
in
Table
I:
TABLE
I
TARGET
AND SEAL-IN
UNIT
2.0
0.6 0.2
Amp
Tap
Amp
Tap
Amp
Tap
0-C
Resistance
0.13
Ohms
0.6 Ohms
7
Ohms
Carry
Continuously
3.5
Amps
1.0
Amps
0.35
Amps
Carry
30
Amps
for
4
Secs.
0.5
Secs.
Carry
10
Amps
for
0.2 Secs.
4

GEK-26423
The normally
closed
contacts
between
terminals
19
and
20 will
close, carry continuously,
or
interrupt
0.3
amperes
in
non-inductive circuits
up
to 250V
DC.
OPERATING
PRINCIPLES
The
inho
type units
in the C[YG51A
relay are
of the four—pole
induction-cylinder
construction
(see
Fig.
6)
with schematic
connections
as
shown in
Fig. 3. The two
side
poles, which
are energized
by the
phase-to-phase
vol
tage
in
quadrature
with the
phase- to—neutral
vol
tage of the
protected
phase, produce
the
polarizing flux.
The
flux
in
the front pole,
which is
energized
by
a
percentage
of the
phase-to-neutral
vultaçje
of Lire
protected
phase,
interacts with the
polarizinq
flux
to
produce
restraint
torque.
The
flux
in
the
rear
pole, which
is energized
by
the
line current
of
the
protected
phase, interacts
with
the
polar
i
z i
rig
flux
to
produce operating
torque.
The
torque at the
balance
point for
the
phase
A
starting unit
can,
therefore, be expressed
by the
following equation:
Torque
= 0
= KI’aEbc
cos
((
-30)
— TE’aEbC’
sin
8
(1)
where:
K
design constant
= Phase-A-to-neutral voltage
at
the
relay location
Ebc
=
Phase B to Phase C voltage
(Eb - E)
at the relay
= Phase
A current, at the
relay location
B = Angle by which
Ea
leads
Ebc’
(900
for
balanced
3-phase condition)
T = Restraint
tap setting
= Angle by which
‘a’
leads
Eb
CHARACTERISTICS
The
operating
characteristics of the
mho
units in the CEYG51A
relay may be represented
on the
R-X
impedance
diagram
as shown
in
Fig.
7.
It
should be
noted that these
steady-state
characteristics
are
for
rather specific
fault conditions
described
below:
The
mho
unit
has
a
circular
characteristic which
passes through
the
origin
of
the R-X diagram.
The
diameter passing
through the origin
defines the angle
of maximum torque of
the unit, which
occurs
when
line current
(a
for example)
leads
the quadrature polarizing
voltage (Ebc
for
example)
by
30°. Since
there
is
essentially
no
phase
shift
in
the
line—to-neutral voltage
for
a
single-phase-to-ground
fault,
this maximum
torque angle (i.e.
maximum reach
angle) occurs
when the line current
lags the
phase—to—neutral
voltage
by
600,
which
is the condition represented
in Fig.
8.
The
diameter of the
impedance circle would
nonially be considered
as
the ohmic
reach of the unit,
which would be
the
basic
minimum
reach
with
the
F tap leads
on
100
percent.
However,
if the
mho
unit
is
not compensated it is
not
an
accurate
distance
measuring
until except
on
3—phase
faults,
or
for the
special case of single-phase—to-ground
faults where the
zero-sequence
impedance to
the fault is
equal to
the positive sequence
impedance
to
the fault.
Instructions
are given in Appendices
II and
III for
selecting a
reach setting.
The ohmic redch of
the
inho
unit can be
extended by reducing the
percentage
of the faut
voltage
applied
to
the restraint
circuit, that
is
by
setting the E 2 tap
leads
on a lower
percentaoe
position on
the tap block.
(Zi)
100
Ohmic Reuch
= 2
E
Tap Setting
()
(5)
5

GEK—26423
The
ohmic
reach
obtained
from
equation
(5)
assumes
that line
angle
and
maximum
torque
angle are
equal
(60°).
The
reduced
reach
at
line
angles
other
than
60°
can
be
obtained
by
multiplying
the
reach
obtained
from
equation
(5)
by
cos (60-0),
where
0
is
the
hne
angle.
PICKUP
The
operating
torque
will close
the
contacts
when
the
fault
urrent
is
in
a
certain direction
and
of
sufficient
magnitude
to
overcome
the
restraint
torque.
The
operating
torque
on
3-phase
faults
is
a
maxi
mum
for
fault
currents
which
lag
the
unity
power
factor
position
by
60
degrees
and
is
reliable
down
to
one
percent voltage
with
currents
as
tabulated
below:
MINIMUM OHMIC
REACH
SETTING
CURRENT
RANGE FOR
RELIABLE
OPERATION
(0-N
OHMS)
0.5
36
-
60
1
18-60
1.5
1?
-
60
2
9
-
60
6
-
60
On
single-phase-to-ground
faults
the
quadrature
polarizing potential
will
remain
quite
high
with
the
result
that
the
relay
will
operate
at
considerably
less
current
than
tabulated.
For
example,
with
a
one
percent
restraint
voltage
and
120
volts
polarizing
the
unit
will
operate
with
less
than
1
ampere
operating
current
for
the
3-ohm
minimum
reach
setting.
OPERATING TIME
For
typical
operating
time
characteristics
see
Figure
13A
and
13B.
BURDEN
The
burden
imposed
on
the
potential
transformers
by
the type
CEYG51A
relay
with
the
restraint
tap
set
at
100
percent
is
as
given
below:
Basic
Rated
Polarizing
Circuit
Restraint Circuit
Ohms
Freq
V
Watts
Vars
VA
Volts
Watts
Vars
VA
1
-
30
60
120
10.1
8.88
13.5
70
2.7
4,0
4.8
0.5
-
15
60
120
10.1
8.88
13.5
70
0.9
1.6
1.8
1
-
30
50
120
8.41 7.38
11.2
70
1.7
3.0
3.4
If
the
restraint
tap
is
reduced,
the
burden
of
the
restraint
circuit
is
given
by
the
following
equation:
VA
Watts
*()2
+
,j
VARS(.j-)
where
Watts
=
Restraint
circuit
watts
from
table
above.
VARS
=
Restraint
circuit
Vars
from
table
above.
T
=
Tap
in
percent.
6

GEK-26423
The
burdens
imposed
on
the
current
transformers
by
the
current
circuits
are
given
below:
Basic
Rated
3-4, 5-6,
or
7-8
Circuit
9-10
Circuit
Ohms
Freq.
I
R
X
Z
I P
X
Z
-
30
60
5
0.070 0.040 0.080
5
0.210 0.120
0.240
0.5
-
15
60 5
0.007
0.005 0.008
5
0.021
0.013
0.024
1
-
30
50
5
0.058 0.033
0.067
5
0.175
0.100
0.200
NOTE:
Above data
is
For
the
mho
units
set
on
their
maximum
ohmic
reach
taps.
The
burden
for
the
lower
reach
tap
settings
will
be
less
than
the
tabulated
burdens.
CALCULATION
OF
SETTINGS
in
applying
the
relay
to
a
particular
line
and
system, the
limitations
outlined
under
APPLICATION
fre
quently
do
not
materialize.
Therefore,
it
is
reconinended
that
the
initial
calculations
of
1
and
2
below
be followed
to
determine
what
final
calculations
may
be
necessary
and
how
the
relay
may
be
applied.
1.
Determine
if
zero
sequence
current
compensation
is required.
This
will
depend
upon
on
evaluation
of
the
necessary rnho
unit
tap
settings
and
the
relation
of
the
resulting
mho
characteristic
with
the
line
power loadings
and
power
swings.
See
Appendix
I,
equations
1b
and
I.
2.
Determine
if
there
is
a limitation
in
the
application
for
incorrect
operation
on
faults
behind
the
relay
terminal.
a.
When
zero
sequence
current
compensation
is
iQi
used:
if
Co
is
equal
to
or
less
than
C,
no
further
evaluation
need
be
made.
See
Appendix
II,
equations
Ha,
lIb
and
lIc.
b.
When
zero
sequence
current
compensation
is
used:
if
(3K
+
1)
Co
is
equal
to
or
less
than
C,
no
further
evaluation
need
be
made.
See
Appendix
III,
equations
lila,
Ilib
and
IlIc.
c.
If
neither
a
nor
b
above
is
applicable,
evaluate
the
equations
of
either Appendix II
or
III
to
determine
if
it
is
necessary
to use
the zero
sequence
directional
overcurrent
supervising
re
lay,
Type
CFPH16A.
The
following calculations
are
made
as
an
example
of
determining
the
actual tap
settings
to be
used.
Consider the
protected line
to
be
between
breakers
A
and
B
on
the
portion
of
a
system
shown
in
Fig.
5.
Assume
the
following
characteristics:
Z 1
=
24.0
/790
primary
ohms
=
72.0
/750
primary
ohms
Z
14.4
L°
primary
ohms
CT
Ratio
=
600/5
PT
Ratio
1200/1
Secondary
Ohms
= CT
Ratio
x
Primary
Ohms
PT
Ratio
=
2.4
/79°
=
0.47
+ j2.36
secondary
ohms
=
7.2
/750
=
1.9
+ j5.95
secondary
ohms
Zom
=
1.4
/75°
=
0.36
+ jl.35 secondary
ohms
Checking
Appendix
I
first
to
establish
the
maximum
tap
setting
that
would
still
permit
the
CEYGSIA
at
breaker
A to
detect
a single
phase
to
ground
fault
(F2)
at the
remote
bus,
Equation Tb
should
be
used.
7

GEK-26423
Assume
for
this
fault
at
F2
that
a
system
study
yields
the
following
quantities.
C 0
=
0.17
C
0.20
‘a’
13.7
secondary
amperes
based
on
600/5
CT’s
10
=
4.1
secondary
amperes
=
-0.88
secondary
amperesbased
on
the
protected
line
CT
ratio
of
600/5.
Note
the
negative
sign
because
I
flows
in
the
opposite
direction
in
the
parallel
line
(D
to
C)
from
that
in which
J flows
in
the
protected
line
(A
to
8).
0
790
Substituting
these
values
and
the
values
of
impedance
assumed
above
into
equation
lb
of
Appendix
1,
we
obtain:
K
Cos
(60—79)
T
r
(7.2
-2.4)(0.17)
(1.4)(-0.88)
‘ 25 L 24
+
(0.4
+
0.27)
+
13.7
T
0.204K
The
value of
I
could
be
obtained
for
all
three
basic
minimum
reach
settings.
However,
the
highest
one
should
be
used.
For
the
three
ohm
basic
reach
settings
K
=
300.
Thus,
for
this
basic
tap
setting
the
restraint
tap
I should
be
no
larger
than:
I
=
0.204K
=
61
percent
Consider
now
a
ground
fault
at
Fl
immediately
behind
the
relay.
Appendix
II
indicatos
the approach
to
calculate
the
maximum
safe
reach
setting
to
eliminate
the
possibility
of
an
incorrect
operation
on
single
or
double
phase
to
ground
faults
at
this
location.
Assume
that
a
system
study
yields
the
following
system
constants:
C
0.27
C 0
=
0.11
Z 1
0.875
secondary
ohms
Z 0
1.05
/780
secondary
ohms
ZQ/Z 1
1.2
Using
the
3
ohm
basic
minimum
tap
settings
established
above
arid
evaluating
equations
ha,
JIb
and
TIc
of
Appendix
II,
the
minimum
permissible
values
of
tap
setting
T
are
tabulated
below.
QUANTITY
VALUE
Zi
0.875
/820
Z 0
1.05
LL8_°
Z 0 /Z 1
1.2
C 0
0.11
C
0.27
100
A
123
8
82°
T
(Equation
ha)
-10.5
Percent
T
(Equation
lib)
-18
Percent
T
(Equation
Tic)
-14.5 Percent
8