APPLICATION
Stabilising differential protection
for an arc transformer
by A Perera and P Keller, Eskom System Operations and Planning
Differential protection on transformers supplying arc furnaces is susceptible to maloperation. After extensive analysis it was discovered that
the arcing process is not the cause of the maloperation. An arc transformer is located between the supply transformer and the furnace.The
main factor causing the maloperation is the inrush current of the arc transformer. The large DC offset in the inrush current results in saturation
of the supply transformer and its current transformers (CTs).
In 1907 the first commercial arc furnace
was commissioned in the United Sates of
America. Since then this method of melting
iron has become very popular around the
world. This process has however introduced
some challenges for the protection
fraternity.
In 2007 the protection on a transformer
in Eskom feeding such an arc furnace
was replaced with a modern digital relay.
Shortly after this change was made this
transformer started to trip on differential
protection for no faults. These unwanted
and unnecessary trips severely impacted
the customer in terms of lost time of
production. The procedure following a
differential operation on a transformer in
Eskom is to first inspect the transformer
before it can be returned to ser vice.
This resulted in substantial lost time of
production.
Network
Fig. 1 shows the network diagram of the
arc furnace installation. The transmission
system has been replaced by an
equivalent source. The Tx transformer is a
120 MVA 275/33 kV Ynd1 transformer. Its
impedance is 8%. The arc transformer is an
80 MVA 30,3/0,6 kV DD transformer with an
impedance of 7,16%. The two filter banks
shown are 13 MVA 5th and 7th harmonic
filters adding up to 26 MVA. The NEC is the
zero sequence source for detection of
earth faults on the 33 kV network. The arc
furnace load is connected at 600 V. At this
voltage level the system impedances are
very low. Table 1 shows the impedances
referred to the 600 V bus bar in primary
ohms.
A 70 MVA load at 600 V has an impedance
of 0,00514 Ω. This impedance is almost an
order of magnitude larger than the source
impedance. The load current is about
75 kA. Figs. 2 to 7 show recordings from a
digital fault recorder of the Tx transformer
MV voltages, currents and power during the
arcing process. The instantaneous wave
forms were converted into RMSt traces for
clarity for the following figures.
The MV voltage of the Tx transformer is
reasonably steady, while the current,
and thus the power, is changing. The
literature on arc furnace loads suggests
this to be the case [1]. These variations
are a function of the smelting cycle of the
furnace, changing faster in the start of the
smelting cycle, and slower towards the end
when most of the pot is molten.
The start up process for the arc furnace
is as follows.



The arc furnace transformer is
energised
The furnace is loaded with scrap metal
and molten metal
The arcing rods are lowered into the
furnace to start the arcing process.
There is a minute to two minutes time lag
from the time the furnace transformer
is energised to the start of the arcing
process. This implies that all the transients
of the energisation of the arc transformer
should be settled by the time the arcing
process starts.
Figs. 5, 6 and 7 show captured waveforms
of the arc furnace load as seen from
the MV bus of the Tx-Transformer at the
start of the arcing process when the arc
is being struck. As can be seen from the
waveform, the load is rich in harmonics
and asymmetrical. In this particular record,
the blue phase arc is only struck about 4 s
into the process.
Trip records
Fig. 1: Network diagram.
Relay recordings of two of the trips that
energize - April 2011 - Page 54
Grid
275/33
kV Trf
33/0.6
kV Trf
Total
0,000024
0,00024
0,0003222
0,000586
Table 1: Impedances referred to 600V Arcbus
happened are shown in Fig. 8. Both of
these were incorrect trips.
Fig. 8 shows the first trip record. The peak
value of the MV L2 current at the start of the
event is 8 kA. The recording shows the L2
differential element picking up about 100
ms into the event at time marker T1. The
blocking elements, wave block and 2nd
harmonic block, prevents the differential
element from issuing a trip. At time marker
T2, about 420 ms from T1, the blocking
elements drop off, and we see the relay
issuing a restrained differential trip. Fig.
9 shows the 2nd trip record. The peak
value of the MV L1 current for this event is
7,7 kA. The differential element picks up
20 ms into the event, but is blocked by the
2nd harmonic blocking element. It drops
off and picks up again 20 ms later. Again
it is blocked by the 2nd harmonic blocking
element. However, 8 ms later the blocking
drops off, and the relay issues a trip. There
have been records on the relay where the
relay picked up for similar looking wave
forms but was blocked correctly.
Theory
To begin to understand why the differential
relay may operate incorrectly it is firstly
important to understand some theor y
with regards to transformer protection
and transformer behaviour under certain
conditions.
The following is a list of typical protection
functions used to protect a power
transformer:



Differential protection (high or low
impedance)
Restricted Earth fault protection
Overcurrent (IDMT and instantaneous)
protection

Earth fault protection

Winding and oil temperature protection

Buchholz protection

Overfluxing protection
All these functions complement each
other to provide comprehensive protection
APPLICATION
Fig. 2: Tx Transformer MV voltage during arcing.
Fig. 3: Tx Transformer MV current duringarcing.
under load and through fault conditions,
while still permitting good sensitivity to
be achieved. This bias characteristic is
shown in Fig. 11. The differential relay
normally has a restrained function and
an unrestrained function. The purpose of
the unrestrained function is to operate for
high values of differential currents. This
function is not supervised by any other
conditions and will operate unconditionally
if the differential currents reach a certain
level. There strained differential function
caters for differential currents of lower
magnitude, but must still remain stable
for false differential currents caused by CT
mismatches, inrush currents, CT saturation
during through faults etc. For this reason
the differential relay is supervised by the
bias current and often restrained by some
other quantity.
Simulations and problem identification
RTDS simulations
Fig. 4: Load snap shot.
Fig. 5: Tx Transformer MV voltage
during arc striking.
Fig. 6: Transformer MV current during arc striking.
Fig. 7: Transformer MV power during arc striking.
for the transformer. We will elaborate a little
with regards to the differential protection
function.
Differential protection theory
Fig. 10 shows the application of differential
protection. Currents that flow through the
transformer will result in zero current in the
differential relay, and currents that flow into
the transformer from both sides will result
in large currents through the relay. Due to
the transformer ratio the currents on the
two sides of the transformer will be different
and the CT ratios should be selected to
compensate for this.
The differential relay must be stable even
if the transformer is operated at a tap
position other than its nominal tap, and
also if a mismatch in the CTs exists. To cater
for these two factors a bias is introduced
that allows the differential relay to be stable
To tr y and solve the problem of the
differential relay mal-operating, it was
studied using a real time digital simulator
(RTDS). The network was modeled using
available data for the Tx transformer,
the arc transformer, the Tx transformer
HV and MV CTs to which the differential
relay is connected. There was insufficient
data to model the transformer protection
CT secondar y circuit. Where data was
not available, i.e. the B-H curve of the
transformers, CT secondar y circuit etc,
engineering judgment was used to
estimate the data. The RTDS arc furnace
load model was used to model the
load. The same make and model of
protection relay, with the relevant settings
was connected to the RTDS. The primary
objective of the tests was to tr y and
recreate a relay mal-operation.
The assumption when the network was
simulated on the RTDS was that the nature
of the currents that the arc furnace load
creates, and their interactions with the
transformers and the CTs, were leading to
the currents that confused the differential
relay. However after a few simulations it
was evident that this was not the case.
Adjusting the parameters of the RTDS arc
furnace load and fine tuning the estimated
data for the transformers did not produce
the wave forms that resembled the relay
trip records. Further, the RTDS simulations
showed that faults on the arc furnace bus
do not create the expected wave forms,
nor does it make the relay mal-operate.
The simulations showed that closing of
the Tx transformer MV breaker created
waveforms that resembled the waveforms
seen in the relay trip records. However,
we were not able to recreate a trip event
at the RTDS. One of the limitations of the
RTDS transformer model was that the initial
fluxes of the magnetic circuits could not
be set. At the start of the simulation the
fluxes would start from zero. To evaluate
the results of certain initial residual flux in
the transformer and the CTs we would have
energize - April 2011 - Page 56
to have a certain sequence of events that
leave the transformer in that state, and
then continue the simulation from that
point onwards to obtain the results. This
is a time consuming process, especially
if one is uncertain as to what the initial
fluxes should be. Thus we did not have
enough time to evaluate the impact of
residual flux.
As can be seen in Fig. 8 and Fig. 9, two
of the criteria used to block the restrained
differential function are 2nd and the 5th
harmonic blocking. When the protection
was changed a few years back, and
the relay started mal-operating, one of
the suggestions to fix the problem was
to reduce the 2nd harmonic blocking
level. However, there was a concern
about setting this too low for the fear of
blocking the relay for an internal fault. The
RTDS transformer model allows simulation
of transformer internal faults. This feature
was used to investigate the 2nd harmonic
current level for internal faults. It was found
that even with the most sensitive setting the
differential protection correctly detected
and tripped for internal faults.
Digsilent simulations
Simulations and the relay trip records
seem to indicate that the onset of the
problem is when the arc transformer is
energized. Armed with this knowledge,
Digsilent power factory software was used
to further investigate this phenomenon.
This investigation was done in parts; first,
the inrush currents on energisation of the
arc transformer were investigated. Then,
the primary DC time constants and the
interactions of primar y and secondar y
time constants were investigated. Finally,
the effect of the arc transformer inrush on
the Tx transformer and the Tx transformer
CTs were investigated.
Arc transformer inrush.
Fig. 12 shows a relay recording of the arc
transformer inrush current as seen by the Tx
transformer MV CTs. The current values are
referred to primary values. For the following
discussion we shall assume that during this
short time period, the Tx transformer MV CTs
faithfully reproduce the primary currents.
Fig. 8: Trip record 1.
Fig. 9: Trip record 2.
APPLICATION
Fig. 10: Differential protection.
Fig. 14 shows the results of the same
simulation, this time the initial flux of the
arc transformer was changed to as follows;
fluxA = -0,25, fluxB = -0,5 and fluxC =
0,8 p.u. The correlation between the
recording and the simulation is now much
better. The initial flux values were arrived
by trial and error. The differences in the
current traces are probably due to the
estimated B-H curve of the arc transformer
being different from the actual, and errors
in the initial flux estimation. This simulation
shows that the residual flux of the arc
transformer will change the inrush current
of the transformer.
Network primary time constant
Fig .11: Diff-Bias characteristic.
Fig. 12: Arc transformer inrush (relay recording).
Fig. 13: Simulation of inrush (initialflux zero).
To investigate the primary network time
constant and the interaction of the primary
and the secondar y time constants the
network shown in Fig. 15 was simulated.
The results are for an A to ground fault
on the bus labeled “Terminal”. Fig. 16
shows the primar y fault currents of two
simulations with two different network R/X
ratios. The green trace is the results with a
network R/X ratio of 0,1, and the red trace
is for an R/X ratio of 0,025. The network
with a smaller R/X ratio has a longer DC
time constant. Take note of the network
and the Tx transformer impedances
mentioned in Table 1. The Tx transformer
impedance is an order of magnitude
l a r g e r t h a n t h e s y s t e m i m p e d a n c e.
Transformer impedance is almost a pure
inductance and it follows that the R/X ratio
of the source impedance seen from the
MV bus of the Tx transformer will have a
small R/X ratio.
To study the effect of arc transformer inrush
the network shown in Fig. 1 was simulated.
A relay record that was triggered by the
energisation of the arc transformer that
did not result in a trip was used to fine
tune the unknown values. Using the MV
voltages as a reference, the initial flux of
the arc transformer was set to match the
relay MV currents. Fig. 17 show the results
of this simulation. The simulated values
were rescaled to primary values so that
they can be compared to the recording.
The 1st peak value of the L2 current is 5 kA.
Once the simulation objects were tuned,
the relay trip record shown in Fig. 8 (which
resulted in an incorrect trip) was used to
test the simulation.
Fig. 14: Simulation of inrush (initialflux set).
From Fig. 12 we can see that the MV
breaker was closed 0,3 ms after the MV
blue (L3) voltage peak. The largest inrush
current is on the white (L2) phase. The 1st
peak value of this current is 5 kA.
Fig. 13 shows the results of a simulation of
closing the breaker at the same point on
wave as the recording.
The currents in Figs. 12 and 13 do not
correlate well. While the peak value of
the L2 current (the green trace on both
the plots) is 5 kA, the other two currents
do not match.
Figs. 18 and 19 show the simulated and
the measured MV and HV L2 currents as
well as the simulated primary currents. All
traces have been scaled so that they can
be plotted on the same graph.
From Fig. 18 we can see that all the
currents start at the same value. 20 ms into
the event the simulation and the recording
deviate. About 100 ms into the event, we
can see the simulated MV CT measuring
errors, which is different to the recording.
About 600 ms into the event simulated CT
and the recording are about the same
value, which is different from the actual
primary value.
energize - April 2011 - Page 57
This may indicate that the MV CT time
constant that is modelled is incorrect.
Fig. 19 shows the HV values. Here the
simulations reasonably match the
recording. We see that about 250 ms
into the event the CTs are not correctly
transforming the primar y current, and
the MV and the HV CTs are behaving
differently, which this leads to a false
differential current. Fig. 20 shows the
simulated magnetising currents drawn by
the Tx transformer. The DC current in the
inrush of the arc transformer is saturating
Tx transformer causing it draw more
magnetizing current. This magnetising
current will cause a genuine differential
c u r r e n t. T h e n o m i n a l m a g n e t i s i n g
current of the Tx transformer is about
3 A. This corresponds to the initial values of
Fig. 20. Therefore at the worst point
(1,2 s) the differential current is about 100 A.
However, as this is magnetising current, the
2nd harmonic content of this current would
be high, blocking the operation of the
differential relay. This simulation assumed
initial fluxes of the Tx transformer to be zero.
Even though we were unable to simulate
conditions that resulted in an incorrect
differential trip at the RTDS, the simulations
done on DigSilent show that the hypothesis
about the cause of the differential trip is
reasonable i.e. the Arc transformer inrush
current causes the Tx Transformer differential
relay to mal-operate.
Proposed solutions
Since the start of the nuisance tripping of
this transformer, many solutions have been
tried. Among these solutions were:






Replacementof the MV CTs to match
the HV CTs. The MV CTs were of the
class 10P20 and the HV CTs are Class
X. The MV CTs were replaced with Class
X CTs and the magnetising curves were
matched.
Some setting changes were also tried.
These included:
Reducing the level of the 2nd harmonic
blocking. The minimum level on the
relay internal transformer faults.
I n c r e a s i n g t h e B i a s / D i f f c u r v e,
essentially making the differential relay
less sensitive.
Enabling cross blocking between the
different phases.
Replacement of the relay with a relay
from another manufacturer.
None of the above stopped the nuisance
tripping.
Present solution
2nd harmonic blocking level.
The 2nd harmonic blocking level has been
decreased to a minimum level of 5%.
Simulations done on the RTDS confirmed
that for faults in the transformer the 2nd
harmonic levels are below this level and
the differential relay will not be blocked.
Overcurrent blocking
An additional over current blocking of the
APPLICATION
Setting the pick-up level of the O/C block
function.
Fig. 21: O/C blocking logic diagram.
Fig.15: Simple network.
Fig. 22: Directional element of O/Cfunction.
Fig16: Effect of the R/X ratio on DC decay.
Fig. 17: Simulated vs Measured
MV CT currents(tuned).
Fig. 18: Simulated vs Measured
MV CT currents(Check).
Fig. 23: Matlab calculations of
magnitude and phase.
restrained differential function for a preset
time has been introduced as shown in
Fig. 21. This element is directionalised
with the voltage on the MV side of the
transformer. A positive sequence voltage
and current is used to establish the
directionality and a 50 Hz rms quantity is
used to establish a current magnitude.
The over current level is set above the full
load of the arc transformer, ensuring that
no blocking will occur under normal load
conditions.
Setting the directional element of the O/C
block function.
Fig. 19: Simulated vs Measured
HV CT currents(Check).
Fig. 20: Tx Transformer magnetising current.
The directional element of the O/C block
function uses positive sequence quantities
of the MV voltage and the MV current.
The O/C pick-up level is set very sensitive
to ensure that the function is active
under inrush conditions as the positive
sequence quantities might be very small.
During the inrush condition the circuit is
predominantly inductive and the current
should lag the voltage by 90°. The MV CT is
starred towards the transformer, thus inrush
currents that flow towards the furnace
will effectively be defined as “reverse”.
The operation of the directional element
can be seen in Fig. 22. RCA is the relay
characteristic angle and ROA is the relay
operating angle.
energize - April 2011 - Page 58
The O/C level element uses 50 Hz rms
quantities. A true rms measurement is not
available in the relay. The level element
is set to 75% of the MV CT ratio (2000:1).
This relates to a primar y current equal
to 1500 A. The full load currentof the
arc transformer is equal to 1400 A. The
setting is above the full load current of
the arc transformer. This function should
thus not pick-up for load conditions.
During the arcing process the relationship
between the voltage and current should
be predominantly resistive, which means
that the directional element should also
not be picked-up. Actual recordings of the
load confirmed this.
The directional element in conjunction
with the O/C level element ensures that
the blocking of the restrained differential
function will only occur under inrush
conditions. Internal transformer faults will
not enable this blocking function. Fig. 23
show the values calculated by Matlab
for the magnetising inrush from the relay
recorded currents. The graphs are the
actual currents, positive sequence current
magnitude, and the positive sequence
current angle with the positive sequence
voltage as the reference. As expected,
before the breaker is closed the current
is leading the voltage (filter bank current).
During the initial stages of the inrush the
current is lagging. Around 1,2 s the positive
sequence magnitude is zero and after this
the positive sequence current changes to
capacitive current again.
Acknowledgement
This paper was presented at the 2010
SAPSP Conference and is reprinted with
permission.
Results
This solution was extensively tested in
the lab before implementation. The test
results were:




For the actual trip records from the
relay this solution prevented the relay
from operating.
For simulated cases with high inrush
currents the blocking function was
picked up.
For simulated cases with low inrush
currents the blocking function did not
pick up. This is not a concern as low
inrush currents should not cause the Tx
Transformeror the CTs to saturate.
The differential relay operated for
simulated internal faults, as created
at the RTDS.
References
[1] RTDS technologies, “RealTime Digital SimulatorPower System Users Manual (page 19-1)”,
November 2006.
[2] Alstom, “NetworkProtection & Automation
Guide – Chapter 6”, July 2002.
Contact Paul Keller, Eskom,
Tel 011 871-2013,
paul.keller@eskom.co.za 