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									                CHAPTER 11


Chapter 11          Page 1   Busbar Protection
                         BUS PROTECTION
Bus Protection Methodologies

Overcurrent Protection

Full Differential

Partial Summation

High Impedance Bus Differential Relaying

Basic Concept

Relay Operation Analysis

Setting the Relay

Low to Moderate Impedance Restrained Differential Relaying

Basic Concept

Multi-restraint Design


Comparison between High impedance and Low Impedance Busbar
Differential Schemes

Busbar Protection Schemes for Various Bus Designs

Chapter 11                   Page 2                  Busbar Protection
The busbars in a substation are possibly one of the most critical elements in a power
system. If a fault is not cleared or isolated quickly, not only could substantial damage
to the busbars and primary plant result, but also a substantial loss of supply to all
consumers who depend upon the substation for their electricity. It is therefore
essential that the protection associated with them provide reliable, fast and
discriminative operation.

As with any power system the continuity of supply is of the utmost importance,
however, faults that occur on substation busbars are rarely transient but more
usually of a permanent nature. Circuit breakers should, therefore, be tripped and not
subject to any auto-reclosure.

The busbar protection must also remain stable for faults that occur outside of the
protected zone as these faults will usually be cleared by external protection devices.
In the case of a circuit breaker failure, it may be necessary to open all of the adjacent
circuit breakers. Tthis can be achieved by issuing a backtrip to the busbar protection.
Security and stability are key requirements of a busbar protection scheme. Should
the busbar protection mal-operate under such conditions, substantial loss of supply
could result unnecessarily.

Many different busbar configurations exist. A typical arrangement is a double busbar
substation with a transfer bar. The positioning of the primary plant can also vary and
also needs to be considered which in turn introduces endless variations, all of which
have to be able to be accommodated within the busbar protection scheme.

Backup protection is also an important feature of any protection scheme. In the event
of equipment failure, such as signalling equipment or switchgear for example it is
necessary to provide alternative forms of fault clearance. It is desirable to provide
backup protection, which can operate with minimum time delay and yet discriminate
with other protection elsewhere on the system.

Chapter 11                             Page 3                            Busbar Protection

Bus protection systems are more straightforward than transformer protection
systems because of the many different variables that are involved with transformer
protection (for example, a 30° phase shift and different ratio CTs).

Bus protection has been the most difficult protection to achieve because of the
severity of an incorrect bus fault relay operation that results in loss of the entire plant
industrial power system. This section will briefly describe the following types of relay
bus protection: overcurrent, full differential, and partial differential.

If the system design does not require fast bus fault clearance, overcurrent relays
(ANSI Device Nos. 51 and 51G) are used to provide bus protection. Referring to
Figure 11-1 and assuming that the bus is fed from a transformer, both devices are
coordinated with the feeder protective devices (ANSI Device Nos. 50/51 and

                                     Figure 11-1.
   Achieving Busbar Differential Protection through the Use of Overcurrent Relays

Chapter 11                              Page 4                            Busbar Protection
Many design standards specify full differential bus protection on all switchgear buses
that are rated 13.8 kV and higher. The basic principle behind full differential
protection is that the phasor sum of all currents that enter and that leave the bus
protection zone be zero, unless there is a fault within the protection zone. Although
differential protection is the most sensitive and reliable method of protecting station
buses, problems can result from the large number of circuits that are involved and
the different energization levels that are encountered in these circuits for external
faults. For example, if there is an external fault on one circuit of a six-circuit bus, five
of the current transformers may supply varying amounts of fault current, but the sixth
and faulted circuit must balance out the total of all the others. Consequently, this six-
circuit bus is energized at a much higher level at or near saturation, and it could
result in possible high false differential currents.

Figure 11-2 illustrates a typical scheme for full differential bus fault protection. A fault
anywhere on the bus will energize either ANSI Device Nos. 87B1 or 87B2 that will
result in a trip of the main, bus, and feeder breakers on the same side of the bus as
the fault location. A fault below the feeder breakers is outside the bus zone of
protection, and consequently, it should only result in tripping of ANSI Device Nos.
50/51 or 50/51G

                    Figure 11-2. Full Busbar Differential Scheme

Chapter 11                              Page 5                             Busbar Protection
Many design standards also specify the use of partial bus differential schemes on
those buses that are rated over 600 V with normally closed (N.C.) bus tie breakers
and where a full bus differential scheme is not required. Figure 11-3 illustrates a
typical scheme for partial differential bus fault protection. For external faults,
negligible current flows in the ANSI Device No. 51 relays. On the other hand, total
fault current is available for bus faults and for faults out on the feeder cables.

                     Figure 11-3. Partial Summation Schemes

Chapter 11                          Page 6                          Busbar Protection
High impedance bus differential relaying is the leading means of bus protection on
high voltage buses and critical medium voltage buses. It also becomes more
predominant on high fault duty switchgear where the enclosed space of the bus
allows little room for dissipation of arc energy.

An AC connection diagram of a high impedance bus differential system is shown in
Figure 11-4. In large substation yards the summation point for the CTs is frequently
made in one or more sub-panels in the yard.

 Figure 11-4. Basic Scheme for High Impedance Busbar Differential Protection

Chapter 11                           Page 7                         Busbar Protection

For CT currents to balance, all CTs must have the same turns ratio. This need for all
CTs to have the same ratio can be a major difficulty of this type of bus protection.


There are two settings to be made on the relay: the voltage pickup setting and the
current pickup setting, selected to prevent operation for external faults.


The worst case condition for which the relay must not operate is the complete
saturation of a CT during an external fault (typically the CT nearest the fault). The
relay voltage setting is based on this condition.

Since each manufacturer has different calibration and safety margins built into its
design, the following settings discussion attempts to remain somewhat generic.

In general, the process begins by assuming that an external fault occurs and the
current is flowing at maximum bus fault levels toward the fault. Next, one assumes
complete saturation of the CT nearest the fault. When the CT saturates, it is
assumed that no other CT saturates. The CT saturation is assumed total, as if the
core can accept no additional flux.

Hence, the CT acts as a negligible reactance air core reactor. Thus, the CT
impedance is reduced to the secondary winding resistance in series with the line
resistance. The relay voltage setting is chosen to ensure that the voltage developed
across the relay under this condition will not exceed the tripping voltage of the relay.

At each CT, the maximum fault level just outside the zone of protection, adjacent to
each CT, is calculated. Using the fault current and CT ratio, the current that flows in
the CT leads is calculated as if the CT had not saturated. However, the current is
considered driven into the saturated CT by other good-performing CTs rather than by
the CT's own internal current transformation effect. This causes a voltage rise at the
CT summation point, conceptually shown in Figure 11-5.

Chapter 11                            Page 8                            Busbar Protection
     Figure 11-5. Concept Voltage Profile, Non-saturated and Saturated CT

The voltage impressed upon the relay connected across the summation point can be
calculated using anticipated current and lead impedance. This must be evaluated for
both phase and ground faults, noting the differing primary currents, lead lengths, and
neutral wire currents in each case, taking into account that current may not return all
the way back to the control house if yard summation cabinets are used. This must be
evaluated for a fault on any line. The worst case is typically associated with a phase-
to-ground fault on the weakest in-feed line.

Chapter 11                            Page 9                           Busbar Protection
Equations used are:


The voltage unit is set at a level corresponding to the voltage calculated above, but
offset from this voltage by some margin factor guidelines given by the
manufacturers. The assumption of total saturation also includes a safety factor
because in actual practice total saturation likely does not occur.

Ideally, the voltage set point would be no higher than the Vknee point of the CT excitation
curve but this is not critical, and manufacturers have guidelines by which the relay
will work successfully with settings above the CT knee points. However, for secure
and reliable performance during an internal fault:


VHighest is the highest summing point voltage calculated for an external fault during the
         saturation of one CT, as previously described K refers to the manufacturer’s
         setting margin guidelines

Vrelay   refers to the relay voltage setting

Vct,rated refers the CT voltage rating, e.g., the ANSI knee point voltage

Chapter 11                              Page 10                             Busbar Protection

The overcurrent element and voltage element trip contacts are in parallel. The
overcurrent element monitors the current through the non-linear impedance. The
setting is intended to add dependability. A typical current setting is equivalent to the
current passing through the non-linear impedance when the voltage at the relay is
equal to the relay’s voltage setting. Consult the manufacturers' manuals for more

                       Figure 11-6. Typical MOV Connection

Chapter 11                            Page 11                           Busbar Protection
Example of High Impedance Bus


The MIB, a member of the M family of protection relays, is a microprocessor based
relay that provides three phase high impedance differential protection for Substation
busbars of any voltage level. Additionally, it can also be used to protect electrical
machines like transformers, generators or motors against restricted earth faults.

Basic protection functions features include a high impedance differential protection
unit. Stability against external faults is guaranteed thanks to the use of a stabilizing

Additionally, the unit includes a set of MOVs (Metal Oxide Varistors) in order to
clamp the secondary peak voltage below 2kV during fault conditions.

Chapter 11                            Page 12                           Busbar Protection

              High impedance differential protection

              Restricted Ground Fault protection with

              One/two elements

               Lockout logic

Monitoring and Metering

              24 Event record per M Family Unit

              Analog/digital oscillography

              Per phase current metering


The relay provides three phase high impedance differential protection for Substation
busbars of any voltage level. Additionally, it can also be used to protect electrical
machines like transformers, generators or motors against restricted earth faults.

Differential Unit (87H)

This unit detects internal faults within the busbars. It is based on a very sensitive
overcurrent differential unit that can be adjusted between 10mA and 400mA. The
relay includes a 2000 Ohm set of stabilizing resistors to make sure that the unit
remains stable for pass-through faults.

In order to protect the unit, a set of MOVs clamps the secondary voltage under faults
to less than 2 kV. Please note that all the CTs must have the same ratio.

Alarm Unit (87L)

The alarm unit detects any current unbalance condition, like the ones produced
when one of the CTs has a phase open. Once the condition is detected a timer starts
that finally blocks the operation of the relay.

Settings go between 10mA and 400mA. Timer is up to 600 sec in steps of 10 ms.

Chapter 11                           Page 13                         Busbar Protection
Restricted Earth Fault

Restricted Earth Fault (REF) protection is intended to provide sensitive ground fault
detection for low magnitude fault currents. This protection is often applied to
machines and transformers having impedance grounded wye windings. It is intended
to provide sensitive ground fault detection for low magnitude fault currents which
would not be detected by other protection functions.

Configurable Logic

Up to a maximum of 4 configurable logic schemes can be implemented into each
MIB relay by means of using a set of 4 preconfigured logic gates and timer cells. A
graphical user interface is provided for configuration of the logic. The outputs of the
configurable logic can be used to configure digital outputs and LEDs.

Multiple Setting Groups

Two separate settings groups are stored in non-volatile memory, with only one group
active at a given time. Switching between setting groups 1 and 2 can be done by
means of a setting, a communication command or digital input activation.

Inputs and Outputs

Two configurable inputs and six contact outputs (four of them configurable) are
provided for each relay.


The relay provides metering values for phase differential current.

Chapter 11                           Page 14                           Busbar Protection

                            Figure 11-7

Chapter 11                  Page 15       Busbar Protection
The relay provides 2 Differential Units, 87 1 and 87 2. Each one can be
enabled/disabled and set independently.

This element consists of overcurrent detectors that measure the current flowing in
the High-impedance differential circuits. The pick up value can be set between 5 mA
and 400 mA, and the time delay from 0 to 600 seconds.

For a Bus-bar differential application, this element will receive the differential
currents corresponding to phase A, B and C. The element will measure the three
differential currents, and operate if any of them surpass the pickup setting during the
specified time delay.

Calculation of Settings
The formulas and procedures described in the following paragraphs for determining
relay settings assume that the relay is connected to the full winding of the
differentially connected CTs. It is further assumed that the secondary winding of
each CT has negligible leakage reactance and that all the CTs have the same ratio.

It is assumed that an external fault causes complete saturation of the CT in the
faulted circuit. The current forced through this secondary by the CTs in the in feeding
circuits will be impeded only by the resistance of the windings and leads. The
resulting IR drop will be the maximum possible voltage that can appear across the
MIB relay for an external fault. The setting of the high impedance differential unit is
expressed as follows:

Chapter 11                           Page 16                           Busbar Protection
              IF (RS + P * RL)
VS =

IR     =      1.6 K


IR   = Pickup setting of the 87 unit

RS   = DC resistance of fault CT secondary windings and leads to housing terminal

RL   = Single conductor DC resistance of CT cable for one way run from CT housing
      terminal to junction point (at highest expected operating temperature.

P    = 1 for three phase faults; 2 for single phase to ground faults

IF   = External fault current – primary RMS value

N    = CT ratio

1.6 = Margin Factor

K    = CT Performance Factor (see Figure 11-10)

RE= stabilizing resistance (2000Ω)

The calculations need only be made with the maximum value of IF for single phase
and three phase faults. If the relay is applicable for these conditions, it will perform
satisfactorily for all faults.

The pessimistic value of voltage determined by the equation, for any of the methods
outlined, is never realized in practice. The CT in the faulted circuit will not saturate to
the point where it produces no assisting voltage.

Furthermore, the condition that caused the fault CT core to saturate also tends to
saturate the cores of the CTs in the in-feeding circuits, which results in a further
decrease in voltage across the MIB. These effects are not readily calculated.

The value of the 87 setting established by the equation is the minimum safe setting.
Higher settings will provide more safety margin, but will result in somewhat reduced

Chapter 11                             Page 17                            Busbar Protection
The method of utilizing the above equation is outlined below:

   a) Determine the maximum three phase and single phase to ground fault
      currents for faults just beyond each of the breakers.

   b) The value of RL is the one-way cable DC resistance from the junction point to
      the fault CT being considered.

   c) For each breaker in turn calculate IR separately utilizing the associated
      maximum external three phase fault current with P=1 and the maximum
      external single phase to ground fault current with P=2.

   d) Use the highest of the values of IR so obtained in c) above.

It is desirable for the pickup current of the 87 unit multiplied by 2000 ohm. to plot
below the knee of the excitation curve (i.e. point on the excitation curve where the
slope is 45º) of all the CTs in use.

Chapter 11                           Page 18                          Busbar Protection
Minimum Fault To Trip 87

After the pickup setting of 87 has been established for an application, a check should
be made to determine the minimum internal fault current that just causeS the unit to
operate. If this value is less than the minimum internal fault current expected, the
pickup setting is suitable for the application. The following expression can be used to
determine the minimum internal fault current required for the particular 87 pickup

IMIN=         [ Σ IX + IR + IM ] * N


IMIN = Minimum internal fault current to trip 87

n=     Number of breakers connected to the bus (i.e. number of CTs per phase)

IX=    Secondary excitation current of individual CT at a voltage equal to pickup
       level of 87

IR =   Pickup level in 87 unit

IM =   Current in the MOV unit at 87 pickup level

N=     CT ratio.

The values of I1, I2, .. etc are obtained from the secondary excitation characteristics
of the respective CTs. The first term in the equation reduces to N*Ix if it is assumed
that all CTs have the same excitation characteristics. The current drawn by the MOV
unit can be obtained from that curve in Figure 11-12 that applies to the relay being

Chapter 11                             Page 19                         Busbar Protection

Pickup Level:      10mA to 400mA

Definite Time:     Up to 600 sec (10 msec steps)


       Level: ±3% in the complete range

       Time: Greater of ±3% or ±25 ms


Pickup Level:      10mA to 400mA

Definite Time:     Up to 600 sec (10 msec steps)


       Level: ±3% in the complete range

       Time: Greater of ±3% or ±25 ms


Value: 2000 Ohm

Max. Operating Cont. Voltage 300 V


V Peak: 1900 V

Max. Withstand Energy: 5400 J

Chapter 11                           Page 20       Busbar Protection
Set an MIB relay to provide busbar protection for the shown system, based on
the above:

System has 30 breakers

All CT ratios are 1200/5

Maximum available 3 phase fault at the bus is 45,000 A Asymmetric

                              30 breakers

             Figure 11-8. Single Line Diagram for Worked Example

Chapter 11                       Page 21                       Busbar Protection
                     Figure 1 1 - 9 . 1 2 0 0 / 5 A CT saturation curve

Calculating R S

The characteristics for the CT are shown in Figure 11-9. The value of RS from
this figure is:

                  Rs = 0.0029 × 240 + 0.113 = 0.809 ohm s

Calculating R L

The cable resistance for the longest CT run is given at 25 0 C. If higher
operating temperatures are expected, this must be taken into account to
determine the maximum expected resistance. Resistance values of wire at
25 0 C, or at any temperature t1 , may be corrected to any other temperature t2
as follows:

             R ( at t2 ) = ( 1 + P1 ( t2 – t1 ) )R ( at t1 )

where:       R (at t1 ) = resistance in ohms at t1

             R (at t2) = resistance in ms at t2

             P1 = temperature coefficient of resistance at t1

For standard annealed copper, P1 = 0.00385 at t1 = 25 °C, the value of RL at
50 0 C is RL = 0.548 ohms.

Chapter 11                                 Page 22                        Busbar Protection
Calculating K

The CT performance factor must be determined next. First, calculate the

Using P = 2 and the knee point ES = 300 V from Figure 11-9, we have:

From Figure 11-10 below, we have K = 0.7 at 1.06.

                       Figure 11-10. CT Performance Factor

The equation for calculating the I pickup setting, taking CT p e r f o r m a n c e and
margin into account, is as follows:

Chapter 11                             Page 23                           Busbar Protection
Given our values for K, RS , P, RL , and N, we have

V across CT ≥ 177.5 * 2000 ≥ 355 Volts (still OK even though the knee of the
                                 CT occurs at 300 volts)

Since the maximum internal fault current is 45,000 Asymmetric (primary
amperes) (equivalent to 188 secondary amperes), the curve of Figure 11-11(at
300 V and 188 A) shows that the application is appropriate for either PVD
and M I B relays.

                     Figure 11-11. Safe limits of application

The next step is to determine the sensitivity of the relay to internal faults. This
may be done using the following equation:

Chapter 11                            Page 24                           Busbar Protection
IMIN=          [ Σ IX + IR + IM ] * N


IMIN     is the minimum internal fault current to trip

n      is the numbers of breakers connected to the bus (i.e. CTs per phase)

IX     is the secondary excitation current of individual CTs at a voltage equal
       to the 87L pickup
       (from CT excitation curve at V = 355 volts)

IR     is the current through the MIB unit to pickup the relay,
       (IR = 177.5 milli-amps)

IM     is the current in the MOV (thyrite) at pickup voltage (pickup current x
       2000); (refer to Figure 11-12)

N      is the CT ratio (N = 240)

Chapter 11                             Page 25                       Busbar Protection
             Figure 11-12. MOV Voltage and Current Characteristics

Therefore, for 30 breakers, the minimum fault current is:

IMIN=         [ Σ IX + IR + IM ] * N

       = [30(0.07 A) + 0.177.5 A + 0.004 A] * 200

       = 548 primary amps

Chapter 11                         Page 26                    Busbar Protection
As we can see, the main limiting factor in regards to the number of feeders an
MIB can support is dictated by the minimum fault current available. In theory, if
we have enough short circuit current and a correct CT dimensioning, there is no
limitation in the number of feeders.

The other limitation is thermal in nature, driven by the presence of any
considerable level of short circuit generated during an internal fault.

The stabilizing resistor and MOV (thyrite) have been designed, on a base case,
to support 50,000 primary amperes for internal faults with CTs of 1250/5 A, and
total operating time of 40 ms (this time is calculated through the sum of the relay,
MOV short circuit latching relay, resistor, and MIB current input).

Finally, to apply the MIB, the following information must be obtained:

•   Minimum short circuit current during internal faults

•   Maximum short circuit current during internal faults

•   Maximum through current during external faults

•   CT ratio of all the CTs

•   Saturation curve of all CTs

•   Secondary CT resistance for all CTs

•   Maximum CT secondary loop impedance (resistance of the lead that
    connect the CT with the relay)

•   Number of feeders in the substation

Chapter 11                          Page 27                         Busbar Protection
The low impedance restrained bus differential scheme is similar in concept to the
familiar transformer restrained differential relay, and some companies have used a
transformer differential relay for this application. There are through current restraint
quantities and differential operate quantities. The restraint and operate windings
interact so that the higher the through current level, the higher the required operate
current. But in the bus relay the restraint and operate circuit may be simpler, the
restraint slope may be fixed, the CT tap adjustment system may not exist, and the
harmonic restraint may not exist.

The operate circuit may contain some impedance. This adds some security against
operation during the poor performance of a CT.


The most involved version of this concept has all CT signals brought into the relay
individually into separate restraint windings before being summed together for the
operate circuit as shown below. Individual tap adjusts may or may not exist on each

                                    Figure 11-13.

                  Multi-restraint Design of Low Impedance Relay

Chapter 11                            Page 28                           Busbar Protection
                                    Figure 11–14

Transformer differential relays are sometimes used for this type of bus protection.
Sometimes questions arise about how to set a transformer differential relay when
used for bus protection.

Transformer differential type relays have little means to differentiate between an
internal fault and the absolute and complete saturation of a CT during an external
fault. The assumed worst case complete saturation of a CT during an external fault
looks identical, to the relay, to an internal fault where the breaker was not supplying
any current (e.g., breaker was open). For these relays to be secure against operation
for an external fault, there must be some assumption of CT performance for an
external fault. There are three approaches: either slow down the relay operation so
that transient DC saturation can be ridden through, use CTs robust enough to only
slightly go into DC induced saturation, and combined with these, the third approach
of setting the relay to not operate for some lower level of CT saturation.

Chapter 11                           Page 29                           Busbar Protection
             •   ABB REB500

Chapter 11                    Page 30   Busbar Protection
Overview of the functionalities REB500 / REB500sys

         Table 11-1 Overview of the functionalities REB500 / REB500sys

Chapter 11                        Page 31                       Busbar Protection
Chapter 11   Page 32   Busbar Protection
Chapter 11   Page 33   Busbar Protection
Chapter 11   Page 34   Busbar Protection
Functionality of REB500 System

Chapter 11            Page 35    Busbar Protection
Chapter 11   Page 36   Busbar Protection
Chapter 11   Page 37   Busbar Protection

High Impedance Schemes                       Low Impedance Schemes
Established technology                       Flexible in case you have multiple
                                             system configurations

Well proven principle                        CT's can be of different CT ratios and
                                             accuracy classes

Simple relay                                 Can add interposing CT's

Simple busbar protection scheme              Establishing a relay setting is relatively

Establishing a relay setting is relatively   Can use same set of CT's for
easy                                         overcurrent and differential protection

All CT's (main and feeder) have to be        Does not usually work unless you have
the same ratio, accuracy, burden, .. etc     numerical relays

Need separate set of CT's for bus
differential relay . Can not use CT's
used for overcurrent relays

All leads from the CT to the relay have
to be of the same impedance

Not practical if you have several
system schemes (scheme not easily

Relay can only be used as a differential
relay. Can not use the relay to perform
breaker failure schemes

Table 11-2. Comparison between High-Impedance and Low-Impedance Busbar
                           Protection Schemes

Chapter 11                              Page 38                            Busbar Protection

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