The InterNational Electrical Testing Association Journal
FEATURE
64S PROTECTION
GUIDE
Theory, Application, and Commissioning of Generator 100 Percent
Stator Ground Fault Protection Using Low Frequency Injection
BY STEVE TURNER,
Beckwith Electric Company, Inc.
This paper covers practical considerations for proper application
and commissioning of this special protection. The total
capacitance to ground of the generator stator windings, bus
work, and delta-connected unit transformer windings is a very
important factor as will be shown. This protection can:
• Detect a stator ground when the winding
insulation first starts to break down and
trip the unit before catastrophic damage
occurs
• Be set to trip in the order of cycles since
the 20 Hz signal is decoupled from the 50
or 60 Hz power system
• Detect grounds close to the machine
neutral or even right at the neutral thus
providing 100 percent coverage of the
stator windings
• Detect grounds when the machine is
starting up or offline
• Reliably operate with the generator
in various operating modes such as a
synchronous condenser and at all levels of
real and reactive power output.
Special steps should be taken in the design
of this protection as there are cases when it
is difficult to distinguish between normal
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operating conditions and an actual ground
fault. The protection must reject fundamental
frequency (50 or 60 Hz) voltage and current
signals that are present during ground faults
on the stator windings. A real life example for
a pump storage facility is included.
S TAT O R G R O U N D FA U LT S
ROOT CAUSES
In-service stator winding failure to ground is a
common generator failure, and there are many
possible causes such as mechanical damage to
the ground wall insulation (category #1) and
fracturing of the current carrying conductor
that result in the ground wall insulation
burning away (category #2).
Examples of category #1 failures:
• ground wall insulation wear-through from
a foreign object or loose component
64S PROTECTION GUIDE
FEATURE
• fracture of the ground wall due to a sudden
short circuit
• deficient ground wall insulation system
• partial discharge combined with vibration
• vibration sparking, inadvertent damage
during maintenance
• wet insulation due to strand header water
leak, bar vibration in the slot
Examples of category #2 failures:
• fracture of stator bar copper conductors
due to high cycle fatigue associated
with vibration
• fracture of bar copper due to gross
overheating of the copper
• core iron melting, failure of a bolted
connection
• failure of a brazed or welded joint
• failure of a series or phase connection
Category #1 failures are typically benign,
unless a second ground occurs, in which
case there is massive arcing. Category #2
failures are always highly destructive to
the generator. Current will temporarily
continue to flow uninterrupted within
the stator bar ground wall insulation (i.e.,
welding arc) when a conductor breaks and
the heat generated is extremely high. This
current will flow inside the insulation until
it is mechanically destroyed. Experience
has shown that the copper is vaporized for
perhaps 8 to 12 inches before the internal
arcing breaks through the insulation wall
and arcs to ground as shown in Figures 1-3.
Conventional neutral overvoltage protection
(59N) cannot detect grounds in the last 5
to 10 percent of the stator winding. If a
failure occurs in a lower voltage portion of
the winding near the neutral, a generator
trip will not typically occur until some
other relay protection detects there is a
problem, (e.g., arcing becomes so widespread that other portions of the winding
become involved). There has been recent
experience with four such failures in large
generators that demonstrate the lack of
proper protection can be disastrous. Each
of the four failures caused massive damage
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Figure 1: Typical Winding Damage Resulting
from Broken Stator Winding Conductor
Figure 2: Typical Core and Winding Damage
Resulting from a Burned Open Bar in a Slot
Figure 3: Burned Away Copper–Fractured
Connection Ring
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FEATURE
to the generator and collectively had a total
cost, including repair and loss of generation,
close to $500,000,000 1. This demonstrates
that failure of stator windings in the last five
percent of the winding is not uncommon.
One hundred percent stator ground fault
protection is provided by injecting a 20
Hz voltage signal (64S) into the secondary
of the generator neutral grounding
transformer through a band-pass filter.
The band-pass filter passes only the 20
Hz signal and rejects out of band signals.
The main advantage of this protection is
it provides 100 percent protection of the
stator windings for ground faults–including
when the machine is off-line (provided that
the 20 Hz signal is present).
AP P LIC AT ION
Figure 4 illustrates a typical application. A
20 Hz voltage signal is impressed across the
grounding resistor (RN) by the 20 Hz signal
generator. The band-pass filter only passes the
20 Hz signal and rejects out of band signals.
The voltage across the grounding resistor is
also connected across the voltage input (VN)
of the 64S function. The current input (IN) of
the 64S function measures the 20 Hz current
flowing on the secondary side of the grounding
transformer and is stepped down through a
CT. It is important to note that the relay does
not measure the 20 Hz current flowing through
the grounding resistor; it measures the 20 Hz
current flowing into the power system. The
20 Hz current magnitude increases during
ground faults on the stator winding and an
overcurrent element that operates on this low
frequency current provides the protection.
20 Hz Voltage and Current 64S Relay
Measurements
The following method shows how to
calculate the 20 Hz voltage and current
measured by the 64S function.
Figure 4: 20 Hz Injection Grounding Network
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FEATURE
Grounding Transformer Turns Ratio (N)
Assume that the turns ratio of the grounding
transformer is equal to:
N = 8,000
(1)
240
Capacitive Reactance
The total capacitance to ground of the
generator stator windings, bus work, and
delta connected transformer windings of the
unit transformer is expressed as C0. Generator
step up transformers have delta connected
windings facing the generator so capacitance
on the high side is ignored. The corresponding
capacitive reactance is calculated as follows:
XCO =
1
2π foCo
(2)
Assume the capacitance to ground is
1 microfarad:
XCO =
=
1
2 • π • (20Hz)• (10 −6 F)
7,958Ω primary
7, 958Ω
N
O
2
=
7, 958Ω
(8, 000 240)
2
= 7.162Ω secondary
Grounding Resistor (RN)
The ohmic value of the grounding resistor
can be sized as follows so as to avoid high
transient overvoltage due to ferroresonance2:
RN =
Xc 0
3
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(3)
=
7.162Ωsec
3
2.387Ω secondary
A value of 2.5 ohms secondary is used for
this example.
20 Hz Signal Generator and Band-pass
Filter Characteristics
The 20 Hz signal generator output is 25 volts
RMS and the band-pass filter has a resistance
equal to eight ohms.
Vsource
= 25∠0° volts
(4)
R Filter
= 8Ω secondary
(5)
Stator Insulation Resistance (RS)
RS is the total insulation resistance from the
stator windings to ground. A typical value
for nonfault conditions is 50,000 ohms
primary. Reflect the insulation resistance to
the secondary of the grounding transformer.
Rs =
50, 000Ω pri
N
2
=
= 45Ω secondary
Reflect the capacitive reactance to the
secondary of the grounding transformer:
XC =
RN =
(
50, 000Ω pri
8, 000
240
)
2
Current Transformer
The current input (IN) of the 64S function
measures the 20 Hz current flowing on the
grounded side of the grounding transformer
and is stepped down through a CT.
CTR = 400/5 = 80/1
(6)
Grounding Network
These are all of the elements needed to
mathematically derive the grounding network
and determine the 20 Hz signals measured
by the 64S function. Figure 5A shows the
insulation resistance and the stator windings
referred to the primary of the grounding
transformer. Figure 5B shows the insulation
resistance and the stator windings reflected to
the secondary of the grounding transformer.
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FEATURE
Figure 5A: 20 Hz Grounding Network – Referred to
Grounding Transformer Primary
Figure 5B: 20 Hz Grounding Network – Reflected to
Grounding Transformer Secondary
XC = total capacitance to ground
RN = neutral resistor
IN = current from system
Rstator = stator insulation resistance
to ground
RFilter = band-pass filter resistance
IBANK = current flow in RN
VN = voltage drop across RN
IT = IBANK + IN
20 Hz Current (IN) Measured by 64S Function
The current input (IN) of the 64S function
measures the 20 Hz current flowing in the
secondary of the grounding transformer and is
stepped down through a CT. As noted previously
the relay does not measure the 20 Hz current
flowing through the grounding resistor.
Total 20 Hz Current Supplied by Signal
Generator – The 20 Hz signal generator looks
into the band pass filter resistance (RFilter) which
is in series with the parallel combination of the
following:
• ZC
• Rs
O
• RN
Therefore, the total loop impedance of the 20 Hz
grounding network can be expressed as follows:
Z T = R Filter
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RS • Z CO
⎛
R
•
N
⎜
RS + Z CO
+ ⎜
⎜ R + RS • Z CO
⎜⎝ N R + Z
S
CO
⎞
⎟
⎟ (7)
⎟
⎟⎠
Z T = 8 + ( 2.5 ) / / ( 45 ) / / ( − 7.162 j)
= 10.135 – 0.706 j Ω secondary
The total 20 Hz current supplied by the
signal generator is determined as follows:
IT =
IT =
V
CTR • ZT
(8)
25∠0°V
80
• (10.135 − 0.706 j Ω)
1
= 30.759 mA
20 Hz Current Measured by 64S Function
(IN) during Nonfaulted Conditions
The 20 Hz current measured by the 64S
function is the ratio of the total current that
flows into the primary side of the grounding
network (ZC //Rs):
O
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FEATURE
Table 1: 20 Hz Current Measurements
IN =
IN =
IT •
RN
ZC • RS
RN + o
ZCo + RS
30.579 •
(9)
2.5
2.5 + (−7.162 j) / /(45)
= 9.779 mA ( Nonfaulted )
20 Hz Current Measured by 64S Function
(IN) during Ground Fault on Stator Windings
A typical value to represent the insulation
resistance of the stator windings when it
is breaking down during a ground fault is
5,000 ohms primary. If the calculations for
equations 7 through 9 are repeated for a fault
resistance equal to 5,000 ohms primary (4.5
ohms secondary), then the 20 Hz current
measured by the relay is as follows:
|IN| = 13.486 mA (5,000 ohm primary
ground fault)
If the calculations for equations 7 through
9 are repeated for a fault resistance equal to
1,000 ohms primary (0.9 ohms secondary),
then the 20 Hz current measured by the
relay is as follows:
RS (primary)
|IN| (secondary)
50,000 Ω
9.779 mA
5,000 Ω
13.486 mA
1,000 Ω
26.640 mA
PRACTICAL CONSIDERATIONS
Here are three important aspects to consider
when applying 100 percent stator ground
fault protection by 20 Hz injection:
• slight change in fault current measured
by relay
• rejection of fundamental frequency (50
or 60 Hz) voltage and current signals
• under-frequency inhibition
Slight Change in Fault Current
A very large capacitance to ground (C0) coupled
with a small value for the grounding resistor
(RN) can result in very little margin between the
fault and nonfault current measured by the 64S
function. Generator windings and isophase bus
work (see Figure 6) are both sources of high
capacitance to ground (ex., a long run of bus
from the generator to the step-up transformer).
|IN| = 26.640 mA (1,000 ohm primary
ground fault)
Table 1 summarizes the 20 Hz current measured
by the relay for nonfaulted and faulted
conditions. Often the 64S protection can detect
the ground for insulation resistance is much
higher than 5,000 ohms primary.
The 64S function can easily distinguish
between nonfault and stator ground faults for
this example. Set the pickup of the 64S, 20 Hz
tuned, overcurrent element above the current
measured during normal operating conditions
but below the current measured for a stator
ground fault equal to 5,000 ohms primary.
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Figure 6: Iso-Phase Bus Work
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FEATURE
Figure 7: Primary Side
Current Distribution
Figure 8: Current Flow in Secondary Network
Figure 7 illustrates why there is not a significant
change in the magnitude of the total neutral
current when there is high capacitance. If the
capacitive reactance is low enough, then only a
small portion of the total neutral current flows
through the insulation resistance. To overcome
this challenge, calculating the real component
of the total neutral current can reliably detect a
stator ground fault for such a system.
Consider the following grounding network
parameters:
N=
8, 000
240
C 0 = 10 µ F → Z C = -0.716j Ω secondary
The 64S 20 Hz tuned overcurrent element
pickup cannot be set such that it reliably
discriminates between nonfaulted and stator
ground fault conditions. The solution is for the
relay to calculate the real component of the 20 Hz
current with respect to the neutral voltage. To do
so, first determine the 20 Hz voltage measured by
the relay voltage input (VN). The 20 Hz voltage
is equal to the drop across the grounding resistor
due to the portion of the total current flowing
through this branch of the grounding network
(i.e., IBANK). Use Figure 8 above to determine the
corresponding equations (10 – 13).
20 Hz Current Flowing through the
Grounding Transformer
O
IBank =
R N = 0.25 Ω secondary
Determine the 20 Hz current measured by
the 64S function for nonfaulted and stator
ground fault conditions using the equations
presented in the previous application section
as shown in Table 2 below.
Table 2: 20 Hz Current Measurements for
High Capacitance
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•
RS (primary)
|IN| (secondary)
50,000Ω
5,000Ω
1,000Ω
12.465 mA
12.096 mA
12.863 mA
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IT – IN
(10)
20 Hz Voltage Drop Across the Grounding
Resistor
VN =
IBank•RN
(11)
Real Component of 20 Hz Current Measured
by 64S Function
Calculate the real component of the relay current
based upon the angle between the relay neutral
voltage (VN) and current (IN) as shown in Table 3.
∅ = ∠VN − ∠IN (12) IReal =
IN i COS(∅) (13)
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FEATURE
Table 3: 20 Hz Current Measurements for
High Capacitance Including Real Component
RS (primary) |IN| (secondary)
Re(IN)
50,000Ω
12.465 mA
0.198 mA
5,000Ω
12.096 mA
1.900 mA
1,000Ω
12.863 mA
8.001 mA
A 20 Hz tuned overcurrent element that operates
on the real component of 20 Hz current measured
by the 64S function can reliably distinguish
between nonfaulted and stator ground fault
conditions when there is high-capacitive
coupling to ground on the stator winding. A
good rule of thumb is to use the real component
of 20-Hz current for sensitive protection if C0 is
greater than 1.5 microfarads and the grounding
resistor is less than 0.3 ohms secondary. The user
can follow the commissioning instructions that
appear at the end of this paper to determine the
total capacitance to ground (C0). If the values
for RN and C0 do not clearly fall under the
category defined by this rule of thumb, then
use the equations provided earlier in this paper
to determine if use of the real component of
neutral current is necessary.
Figure 9 illustrates the fundamental voltage
drop (50 or 60 Hz) across the grounding
resistor as a function of the ground fault
location along the stator windings. Table
4 shows the voltage drop as the fault
location moves from the neutral end of the
stator windings to the output terminals.
Thegrounding transformer is rated 110
volts secondary; the grounding resistor is
sized 0.32 ohms secondary; and the CT
ratio is 400:5 (80:1). The corresponding
fundamental component circulating current
is shown as well. If the fundamental current
is not well rejected, then high magnitude
circulating current can saturate the neutral
current input and, as a result, the protection
will measure a value of 20 Hz current less
than the actual value. Saturation causes the
following problems:
• delayed operation or, even worse, no operation
at all
• less than 100% coverage of the stator windings
as the ground fault location moves towards
the generator output terminals.
NOTE
Saturation is most likely to occur when the
grounding resistor is sized less than one
ohm secondary.
NOTE
If the 64S function uses the real component,
it should also use the total neutral current as
a backup for the case of a solid short circuit
located right at the machine neutral (i.e., the
real component equals zero for this case since
there is no reference voltage).
Rejection of Fundamental Frequency
(50 or 60 Hz) Voltage and Current Signals
Fundamental component voltage and current
present at the relay measuring inputs during
stator ground faults can prevent the 64S
function from operating properly unless they
are well rejected. Note that these signals are not
eliminated by the band-pass filter since they are
due to the fundamental voltage drop across the
secondary of the grounding transformer.
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Figure 9: Fundamental Voltage across RN as
Function of Ground Fault Location
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FEATURE
Table 4: Fundamental Voltage Drop Across Grounding Resistor and Circulating Current (RN = 0.32 Ω)
Fault Location
VS
IS
100% (phase side)
110 V
(110 V)/0.32 Ω = 343.75 amps
4.297 amps
90%
99 V
(99 V)/0.32 Ω = 309.375 amps
3.867 amps
80%
88 V
(88 V)/0.32 Ω = 275 amps
3.438 amps
70%
77 V
(77 V)/0.32 Ω = 240.625 amps
3.008 amps
60%
66 V
(66 V)/0.32 Ω = 206.25 amps
2.578 amps
50%
55 V
(55 V)/0.32 Ω = 171.875 amps
2.148 amps
40%
44 V
(44 V)/0.32 Ω = 137.5 amps
1.719 amps
30%
33 V
(33 V)/0.32 Ω = 103.125 amps
1.289 amps
20%
22 V
(22 V)/0.32 Ω = 68.75 amps
0.859 amps
10%
11 V
(11 V/0.32 Ω = 34.375 amps
0.430 amps
0% (neutral side)
0
Table 4 provides magnitudes of the variables
at various fault locations along the winding.
Underfrequency Inhibition
Sometimes it is necessary to block the 64S
function during conditions such as startup
when the system voltage measured by the
relay is 40 Hz or lower. The third harmonic
of 7 Hz is very close to 20 Hz during
startup when the generator is transitionally
through the lower frequencies and can cause
unwanted operation.
C OM M IS SIO NI NG
INS T R UC T IO NS
Figure 10 illustrates how to configure the
64S protection for commissioning.
NOTE
Use the 20 Hz signals captured during normal
operating conditions to determine appropriate
overcurrent pickup settings. Determine the
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0
IS/CTR
0
total capacitance to ground and calculate the
overcurrent pickup setting based upon these
field measurements as a check.
Stator Ground Fault at Machine Neutral
Configure the power system as follows:
• High side breaker is open.
• The generator is offline.
• Generator terminals are connected
to delta windings of the generator step
up transformer.
• Switch F1 is closed.
• Switch F2 is open.
• 20 Hz signal generator is online.
Place a single line-to-ground fault at location
F1 (switch F1 closed) and measure the 20 Hz
IN. This measurement corresponds to a short
circuit applied at the neutral of the machine
(see Figure 11 on the following page).
The total 20 Hz neutral current (IN) should
be very close in magnitude to 39 mA.
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FEATURE
Figure 10: 20 Hz Grounding Network for Commissioning
I sc =
25
400
8ohmsX
5
= 39mA
NOTE
This is the first step and is a quick check to see
if all the wiring is correct.
Normal Operating Conditions
Configure the power system as follows:
• High side breaker is open.
• Generator terminals are connected to
delta windings of the generator step up
transformer.
• Switch F1 is open.
• Switch F2 is open.
• 20 Hz signal generator is online.
• Preferably the generator is online.
Measure the following 20 Hz signals:
• VN (neutral voltage)
• IN (neutral current)
• Re(IN)(real component of neutral current)
These signals correspond
operating conditions.
to
normal
VN and IN are the 20 Hz signals applied to
the relay inputs. Record VN, IN, and Re(IN).
Modern numerical generator relays can meter
these values. The signals recorded in Figure
11 were captured while commissioning a
large pumped storage hydroelectric unit while
operating in the motoring (pumping) mode.
Figure 12: Numerical Generator Relay
20 Hz Metering
Figure 11: Short Circuit at Machine Neutral
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FEATURE
CONCLUSIONS
This special protection provides 100 percent
coverage of the stator windings for ground faults
under all operating conditions including variable
real and reactive power output and when off-line.
Grounds on the last five percent of the stator
windings do occur and can be disastrous if not
quickly detected. Traditional protections (59N,
27TH, 27D) may not reliably operate for faults
in the last five percent of the stator winding.
The total capacitance-to-ground of the generator
stator windings, bus work, and delta-connected
unit transformer windings is a very important
factor and must be known to ensure the protection
settings are correctly determined. This value can be
determined during commissioning.
There are cases when it is difficult to distinguish
between normal operating conditions and an
actual stator ground fault unless special steps are
taken in the design of this protection. A good
rule of thumb to decide if the real component
of 20 Hz current is necessary is when C0 is
greater than 1.5 microfarads and the grounding
resistor is less than 0.3 ohms secondary. Use the
real component of the 20 Hz current measured
by the relay for these cases.
The protection must reject fundamental
frequency (50 or 60 Hz) voltage and current
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signals that are present at the relay measuring
inputs during ground stator ground faults.
Use an under-frequency element that operates
on the system voltage to block the 64S
function if nuisance tripping occurs during
either startup or shutdown of the generator.
REFERENCES
1. Maughan, Clyde V., “Stator Winding Ground Protection
Failures”, ASME POWER 98151-2013
2. Macon, Russell C., “The Art and Science of Protective Relaying”,
Wiley 209-210, 1956
Steve Turner is a Senior Applications
Engineer at Beckwith Electric Company,
Inc. His previous experience includes
working as an application engineer with
GEC Alstom for five years, an application
engineer in the international market
for SEL, focusing on transmission line
protection applications. Steve worked for
Progress Energy, where he developed a patent for double-ended
fault location on transmission lines and was in charge of all
maintenance standards in the transmission department for
protective relaying.
Steve has both a BSEE and MSEE from Virginia Tech
University. He has presented at numerous conferences
including Georgia Tech Protective Relay Conference, Western
Protective Relay Conference, ECNE, and Doble User Groups,
as well as various international conferences. Steve Turner is
also a senior member of the IEEE.
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