Siemens Solkor 7PG2114 User guide

7PG2113/4/5/6 Solkor Applications Guide
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©2010 Siemens Protection Devices Limited
7PG2113/4/5/6
Feeder Protection
Document Release History
This document is issue 2010/08. The list of revisions up to and including this issue is:
2010/08 First Issue
Software Revision History
2009/04 2436H80003R1g-1c 7PG2113/5
2436H80004R1g-1c 7PG2114/6
First Release

7PG2113/4/5/6 Solkor Applications Guide
Contents
Section 1: Pilot Wire Current Differential Scheme.................................................................................................... 4
1.1 General ................................................................................................................................................... 4
1.2 Information required when ordering ........................................................................................................ 4
1.3 Equipment Options ................................................................................................................................. 5
1.3.1 Solkor Plain/Overcurrent Protection Schemes .......................................................................... 5
1.3.2 Pilot Supervision 5kV Schemes ................................................................................................ 5
1.3.3 15kV Schemes.......................................................................................................................... 5
1.4 Application Diagrams .............................................................................................................................. 6
1.5 Essential External Wiring and Settings ................................................................................................... 8
1.5.1 Description of Typical Setting file. ............................................................................................. 9
1.6 Application Considerations.................................................................................................................... 11
1.6.1 Overcurrent Guard .................................................................................................................. 11
1.6.2 5/15kV Isolation Voltage ......................................................................................................... 11
1.6.3 Pilot Cables............................................................................................................................. 11
1.6.4 Pilot Supervision ..................................................................................................................... 12
1.6.5 Injection Intertripping............................................................................................................... 12
1.6.6 Capacitive Charging Currents................................................................................................. 13
1.6.7 N/N1 Setting............................................................................................................................ 13
1.6.8 In-Zone Tapped Load (Bleed-Off) ........................................................................................... 13
Section 2: Additional Functions.............................................................................................................................. 14
2.1 Multiple Settings Groups ....................................................................................................................... 14
2.2 Binary Inputs ......................................................................................................................................... 15
2.2.1 Alarm and Tripping Inputs ....................................................................................................... 15
2.2.2 The Effects of Capacitance Current ........................................................................................ 16
2.2.3 AC Rejection ........................................................................................................................... 16
2.3 Binary Outputs ...................................................................................................................................... 18
2.4 LEDs ..................................................................................................................................................... 18
Section 3: Protection Functions ............................................................................................................................. 19
3.1 Time delayed overcurrent (51/51G/51N)............................................................................................... 19
3.1.1 Selection of Overcurrent Characteristics................................................................................. 20
3.1.2 Reset Delay ............................................................................................................................ 21
3.2 Voltage dependent overcurrent (51V) ................................................................................................... 22
3.3 Cold Load Settings (51c)....................................................................................................................... 22
3.4 Instantaneous Overcurrent (50/50G/50N) ............................................................................................. 23
3.5 Directional Protection (67)..................................................................................................................... 24
3.5.1 2 Out of 3 Logic....................................................................................................................... 26
3.6 Directional Earth-Fault (50/51G, 50/51N, 51/51SEF)............................................................................ 27
3.7 High Impedance Restricted Earth Fault Protection (64H) ..................................................................... 28
3.8 Negative Phase Sequence Overcurrent (46NPS) ................................................................................. 29
3.9 Undercurrent (37).................................................................................................................................. 30
3.10 Thermal Overload (49) .......................................................................................................................... 30
3.11 Under/Over Voltage Protection (27/59) ................................................................................................. 31
3.12 Neutral Overvoltage (59N) .................................................................................................................... 32
3.12.1 Application with Capacitor Cone Units .................................................................................... 33
3.12.2 Derived NVD Voltage .............................................................................................................. 33
3.13 Negative Phase Sequence Overvoltage (47) ........................................................................................ 33
Section 4: CT Requirements .................................................................................................................................. 34
4.1 CT Requirements for Current Differential Protection............................................................................. 34
4.1.1 Example Fault Current Estimation .......................................................................................... 35
4.2 CT Requirements for Overcurrent and Earth Fault Protection .............................................................. 37
4.2.1 Overcurrent Protection CTs .................................................................................................... 37
4.2.2 Earth Fault Protection CTs...................................................................................................... 37
4.3 CT Requirements for High Impedance Restricted Earth Fault Protection ............................................. 37
Section 5: Control Functions .................................................................................................................................. 38
5.1 Auto-reclose Applications...................................................................................................................... 38
5.1.1 Auto-Reclose Example 1......................................................................................................... 39
5.1.2 Auto-Reclose Example 2 (Use of Quicklogic with AR) ............................................................ 40
5.2 Quick Logic Applications ....................................................................................................................... 41
5.2.1 Auto-Changeover Scheme Example....................................................................................... 41
Section 6: Supervision Functions........................................................................................................................... 42
6.1 Circuit-Breaker Fail (50BF) ................................................................................................................... 42
6.1.1 Settings Guidelines ................................................................................................................. 42
6.2 Current Transformer Supervision .......................................................................................................... 44
6.3 Voltage Transformer Supervision (60VTS) ........................................................................................... 45
6.4 Trip/Close Circuit Supervision (74T/CCS)............................................................................................. 46
6.4.1 Trip Circuit Supervision Connections ...................................................................................... 46
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6.4.2 Close Circuit Supervision Connections ................................................................................... 48
6.5 Inrush Detector (81HBL2) ..................................................................................................................... 48
6.6 Broken Conductor / Load Imbalance (46BC) ........................................................................................ 48
6.7 Circuit-Breaker Maintenance................................................................................................................. 49
List of Figures
Figure 1.4-1 Installation with Existing Solkor R, Rf or R/Rf relay. ............................................................................ 6
Figure 1.4-2 Standard 5kV Solkor R/Rf with Guard. ................................................................................................ 6
Figure 1.4-3 Installation with existing 15kV Plain Solkor Rf with Guard. .................................................................. 6
Figure 1.4-4 5kV Solkor Rf with Pilot Supervision.................................................................................................... 7
Figure 1.4-5 15kV Solkor Rf with Pilot Supervision.................................................................................................. 7
Figure 1.5-1 Interconnection Wiring ........................................................................................................................ 8
Figure 2.1-1 Example Use of Alternative Settings Groups..................................................................................... 14
Figure 2.2-1 Example of Transformer Alarm and Trip Wiring................................................................................. 15
Figure 2.2-2 Binary Input Configurations Providing Compliance with EATS 48-4 Classes ESI 1 and
ESI 2................................................................................................................................................ 17
Figure 3.1-1 IEC NI Curve with Time Multiplier and Follower DTL Applied............................................................ 19
Figure 3.1-2 IEC NI Curve with Minimum Operate Time Setting Applied............................................................... 20
Figure 3.1-3 Reset Delay ....................................................................................................................................... 21
Figure 3.4-1 General Form of DTL Operate Characteristic .................................................................................... 23
Figure 3.5-1 Directional Characteristics ................................................................................................................. 24
Figure 3.5-2 Phase Fault Angles............................................................................................................................ 25
Figure 3.5-3 Application of Directional Overcurrent Protection .............................................................................. 25
Figure 3.5-4 Feeder Fault on Interconnected Network........................................................................................... 26
Figure 3.6-1 Earth Fault Angles ............................................................................................................................. 27
Figure 3.7-1 Balanced and Restricted Earth-fault protection of Transformers ....................................................... 28
Figure 3.7-2 Composite Overcurrent and Restricted Earth-fault Protection ........................................................... 29
Figure 3.10-1 Thermal Overload Heating and Cooling Characteristic.................................................................... 30
Figure 3.12-1 NVD Application............................................................................................................................... 32
Figure 3.12-2 NVD Protection Connections ........................................................................................................... 32
Figure 5.1-1 Sequence Co-ordination .................................................................................................................... 38
Figure 5.1-2 Example of Logic Application............................................................................................................. 40
Figure 5.2-1 Example Use of Quick Logic.............................................................................................................. 41
Figure 6.1-1 Circuit Breaker Fail ............................................................................................................................ 42
Figure 6.1-2 Single Stage Circuit Breaker Fail Timing ........................................................................................... 43
Figure 6.1-3 Two Stage Circuit Breaker Fail Timing .............................................................................................. 43
Figure 6.4-1 Trip Circuit Supervision Scheme 1 (H5)............................................................................................. 46
Figure 6.4-2 Trip Circuit Supervision Scheme 2 (H6)............................................................................................. 47
Figure 6.4-3 Trip Circuit Supervision Scheme 3 (H7)............................................................................................. 47
Figure 6.4-4 Close Circuit Supervision Scheme..................................................................................................... 48
List of Tables
Table 3-1 Application of IDMTL Characteristics .............................................................................................. 21
Table 6-1 Determination of VT Failure (1 or 2 Phases) ................................................................................... 44
Table 6-2 Determination of VT Failure (1 or 2 Phases) ................................................................................... 45
Table 6-3 Determination of VT Failure (3 Phases) .......................................................................................... 45
Table 6-4 Magnetic Inrush Bias ....................................................................................................................... 48

7PG2113/4/5/6 Solkor Applications Guide
Section 1: Pilot Wire Current Differential Scheme
1.1 General
The 7PG2113 and 7PG2114 relays provide both pilot wire current differential protection and overcurrent and earth
fault protection as well as other additional functions. The 7PG2115 and 7PG2116 additionally provide directional
functionality for the overcurrent and earth fault protection. The Overcurrent and earth fault functions are typically
configured to provide an Overcurrent and Earth fault Guard function and can also provide backup protection for
the current differential function.
The current differential trip contacts can be connected in series with the contacts of an Overcurrent Guard relay to
avoid operation for damaged pilots during normal levels of load current. The 7PG2113, 7PG2114, 7PG2115 and
7PG2116 relays provide both the Pilot Wire differential protection and the Guard function as well as other
additional protection functions.
Additional external Pilot Supervision equipment can be supplied to detect pilot cable open circuit which can lead
to protection operation.
Solkor R and Solkor Rf are well established pilot wire feeder differential protections operating on the current
balance principle and are suitable for application on privately owned 2 core pilots with loop resistance up to
2000ohms to protect 2 ended feeder circuits up to 20km in length. Two identical relays are used as a pair with
one relay connected to current transformers at each end of the feeder respectively.
The relay has an insulation level of 5kV between pilot connections and the local ground to withstand voltages
induced on the pilot cable due to coupling with the fault current flowing in a parallel path and to withstand
differential ground voltages caused by the flow of fault current. This is generally adequate for distribution feeders
but for higher voltage systems where feeders may be longer and fault levels higher, an additional external
isolation transformer is available for use with the relay in Rf mode to increase the voltage withstand to 15kV. One
transformer should be fitted at each end of the pilot connection.
The R/Rf relay is primarily intended for use in the Rf mode which has the advantage of increased operating speed
but can be simply changed to R mode for compatibility with pre-installed remote end relays which are older 5kv
Solkor R type relays. The 7PG2113/4/5/6 Solkor relays and 7PG2111 Solkor R/Rf relays are not compatible with
the older 15kv Solkor R system, Solkor A or Solkor B.
1.2 Information required when ordering
7PG2113/4/5/6 Protection relay
CT secondary Current Rating
Insulation level (5/15kV)
Set as R or Rf mode
Non Directional / Directional Overcurrent & Earth Fault
Auxiliary DC supply
Binary Input/Output requirements
External Pilot Supervision devices
Case Styles
System Frequency (50/60Hz) (used for B22 relay setting)
Send or Receive End
Insulation level (5/15kV)
Auxiliary DC supply
Intertripping
Intertripping is not compatible with 7PG2113/4/5/6 used as Guard Relays
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7PG2113/4/5/6 Solkor Applications Guide
1.3 Equipment Options
The following equipment lists provide an overview of the equipment normally required, highlighting differences for
the various scheme options. These lists should be used in conjunction with the diagrams that follow.
1.3.1 Solkor Plain/Overcurrent Protection Schemes
7PG2113/4/5/6 relay (5kV), 1 per feeder end
15kV isolation transformer, 1 per feeder end if required
1.3.2 Pilot Supervision 5kV Schemes
1.3.2.1 Send End
Pilot Supervision Send End relay (transformer+rectifier), 1 per circuit
B22 AC Supply Supervision relay, 1 per circuit
1.3.2.2 Receive End
Pilot Supervision Receive End relay (B74 & B75), 1 per circuit
Note: Although the 5kV scheme utilises a combined B75/B74 unit, the additional isolation requirements at 15kV
necessitate that separate units must be used.
1.3.3 15kV Schemes
1.3.3.1 Send End
15kV Pilot Supervision Send End relay (transformer+rectifier), 1 per circuit
B22 AC Supply Supervision relay, 1 per circuit. 5kV insulation as this is not connected to the pilots.
1.3.3.2 Receive End
15kV B75 relay, 1 per circuit
B74 relay, 1 per circuit
Note: Although the 5kV scheme utilises a combined B75/B74 unit, the additional isolation requirements at 15kV
necessitate that separate units must be used.
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7PG2113/4/5/6 Solkor Applications Guide
1.4 Application Diagrams
The R or Rf mode of the relays at each end must be the same. This applies to any of the arrangements shown.
Figure 1.4-1 Installation with Existing Solkor R, Rf or R/Rf relay.
Figure 1.4-2 Standard 5kV Solkor R/Rf with Guard.
Figure 1.4-3 Installation with existing 15kV Plain Solkor Rf with Guard.
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7PG2113/4/5/6 Solkor Applications Guide
Figure 1.4-4 5kV Solkor Rf with Pilot Supervision.
Figure 1.4-5 15kV Solkor Rf with Pilot Supervision.
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7PG2113/4/5/6 Solkor Applications Guide
1.5 Essential External Wiring and Settings
The relay requires external wiring connections to provide the interaction between the electromechanical pilot wire
differential module and the numeric module. This wiring is not fitted at the factory which allows the customer to
customise wiring routing and ferrule marking to suit customer preference and site specific requirements. Current
transformer wiring must be fitted in line with the standard diagrams to connect the Solkor module and numeric
module. Input/output interconnections are required to take advantage of the features provided by the numeric
module. Details of this wiring is shown on the product wiring diagrams and in Chapter 5: Installation, in this
manual.
The settings supplied in the 4 available settings groups are designed to provide a typical scheme for use as a
basis for site specific settings to suit the required application. These settings provide the functionality of
Overcurrent and Earth Fault Guard, Backup Overcurrent and Earth Fault and monitoring of the Pilot Wire
protection.
It is recommended that the tripping contact of the Pilot wire protection is hardwired via a Guard contact to the
circuit breaker. Additional delay caused by routing this signal into a binary input to apply programmable logic in
the numeric module is undesirable. Instead, the simple Guard logic is achieved by series connection of the two
contacts and an additional contact from the pilot wire module should be wired into the numeric module to provide
an alarm signal which is used to provide auxiliary functions. This signal is used to drive indication, raise an event
on the comms protocol , initiate a waveform record and can be used to drive additional repeat contacts and as an
input to additional user logic.
Similarly, the Guard relay contact which is driven from Overcurrent and Earth Fault elements should be set to
operate a contact which is wired in series with the circuit breaker trip coil. This contact can be set to be operated
continuously by energising the Guard Override Binary Input. This contact can also be shorted out externally by a
panel switch to physically remove the Guard function. This method ensures that the CB can still trip with the
Guard relay de-energised or removed.
The Backup Overcurrent and Earth Fault function can provide a separate contact for CB tripping. An inhibit input
is configured for this function also so that the backup protection can be switched off.
Internal user logic is programmed in the settings file to provide trip indication when the Solkor Rf module operates
co-incidentally with the OC/EF Guard. Operation of the Solkor Rf module in the absence of a Guard relay pickup
is indicated separately. This can indicate a problem with the pilot connection but Guard settings must be
considered in this conclusion since this indication will be raised if a low level fault can occur below the settings of
the Guard but high enough to operate the differential protection. Time delay settings can be applied to avoid
nuisance indications.
Figure 1.5-1 Interconnection Wiring
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7PG2113/4/5/6 Solkor Applications Guide
1.5.1 Description of Typical Setting file.
1.5.1.1 Relay Binary Inputs
Reference
(e.g. I1 =Binary
Input 1)
Connection Description
I1 Energised from Solkor R/Rf
module contact.
This triggers indication and a waveform record regardless of
the Guard relay/Trip.(A separate contact is wired externally via
a Guard contact for the trip circuit.)
I2 Energised from Guard
Override panel switch
(latched)
The switch must also short the external guard contact to allow
removal/switch off of relay DC
I3 Backup OC/EF Inhibit from a
panel switch (latched)
Mapped as an inhibit on 51-2
1.5.1.2 User Logic
Reference Setting Description
V1 50-1 or 50G-1 Guard elements
operated
This is used to generate the Trip indication for 87L+Guard or
87L+ Guard Override
E1 I1.!V1.!I2 87L without Guard when Guard Override is not raised
Used to indicate a possible pilot open circuit, (Low level faults
below the guard setting may cause nuisance indications)
E2 (I1.V1)+(I1.I2) Indication of trip condition, (87L and Guard operation) or (87L
when Guard Override is raised).
This is an indication of trip condition, it is used to start
Waveform Recorder and Fault Record. It is also operates
the Trip output contact used by Backup OC/EF although it
is expected that the main trip will be direct from the Solkor
R/Rf module output contactor via a Guard contact/guard
override switch connected externally
1.5.1.3 Relay Binary Outputs
Reference
(e.g. O1 =Binary
Output 1)
Setting Description
O1 Protection Healthy
O2 Guard Relay Operated
(50-1 & 50G-1) & also
Guard Override
This is the main Guard contact for the trip circuit
O3 87L Solkor operated This is for alarm/test only
O4 Backup Overcurrent,
Earth Fault & E2
(=87L+Guard or
87L+Guard Override))
This is the trip output which starts a Fault Record
O5 E1 (=87L without
Guard)
This gives an alarm that the Solkor has tripped without the Guard
This could indicate pilot open circuit
(note that a fault occurs below the Guard setting but above the Rf
setting will create an alarm)
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7PG2113/4/5/6 Solkor Applications Guide
1.5.1.4 LED mapping
Reference Setting Description
L1 87L operation (Red) With or without Guard
L2 Backup OC & EF (Yellow Pickup, Red Trip)
L3 Guard OC & EF, (Yellow, self reset)
L4 A (Yellow, self reset)
L5 B (Yellow, self reset)
L6 C (Yellow, self reset)
Phase leds are illuminated for Guard and
Backup and are self reset, led state is stored
in the Fault display for Backup and 87L trips.
i.e. Guard operated phase leds are shown for
Solkor trips.
L7 Earth (Yellow, self reset ) Operated by Backup EF & Guard EF, Self reset to
match A,B&C indications
L8 Guard Override (Yellow) Self reset, follows binary input
L9 Backup inhibited (Yellow) Self reset, follows binary input
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7PG2113/4/5/6 Solkor Applications Guide
1.6 Application Considerations
1.6.1 Overcurrent Guard
Traditional Guard relays are connected to the same CTs as the current differential protection relay and the output
contacts are connected in series such that a differential operation will not cause a CB trip if the current in the
guard relay (and therefore the local end) is below setting. This functionality is achieved in the 7PG2113-6 relays
by the overcurrent and earth fault elements that are provided in the numeric module.
Default relay settings on the numeric module provide this functionality along with the recommended external
wiring.
Phase fault Guard relays should be set to at least 150% of maximum load current for stability but less than 50% of
the minimum expected phase fault current. These 2 requirements may conflict and a compromise may be
required.
Earth fault guard relays should be set to less than 50% of the minimum earth fault but more than 150% of the
maximum residual expected due to load imbalance. It is important to note that if an electromechanical, variable
setting relay is used as a guard relay, if a low setting is selected the AC burden at rating will be increased. This is
not the case when a modern numerical relay such as the 7PG2113-6 since this will have a fixed burden
independent of the relay setting. The lower burden of the numeric relay may be a major advantage in this
application.
Care should be taken when applying guard relays that the fault infeed will be available to operate the guard relay
for all fault types. Application of Guard relays to radial systems may be limited.
1.6.2 5/15kV Isolation Voltage
Any electrical current which flows in a path parallel to the pilot cable will cause a voltage to be induced along the
pilot cable. This voltage can become significant for large values of current, long lengths of parallel path and higher
mutual coupling factors caused by poor screening or close proximity of current paths. This voltage can lead to
flashover inside of the relay case from the circuits connected to the pilots to the relay case and local ground. The
problem can be worsened by ground voltage shift between the two substations at the feeder ends due to earth
fault current. Earth shift voltage is often ignored in cable power systems because of the high percentage of the
earth fault current which returns through the cable sheath and armouring, however with overhead line systems the
earth shift voltage can be as significant as the induced longitudinal voltage.
The 7PG2113/4/5/6 relay will withstand 5kV rms voltage. This can be increased to 15kV by the addition of an
isolation transformer.
5kV isolation is usually acceptable for 11kV cable distribution systems where zero sequence currents are
relatively low and protected feeder lengths and therefore parallel runs are relatively short. For higher voltages
where longer feeder lengths are common15kV insulation may be required but 5kV may be acceptable if fault
levels are low or feeder lengths are short.
The pilot cores should be allowed to ‘float’ with neither core earthed at either end. Capacitive coupling to the local
ground along the cable length will ensure that voltage at either end will cause the pilot voltage to remain
symmetrical to the ground voltage such that the withstand requirement at each end is approximately half of the
longitudinal induced voltage.
Induced voltage is proportional to parallel length, maximum parallel current and the coupling or screening factor
between the pilot and the current path. This can be very difficult to assess accurately by calculation and cannot
generally be measured.
The maximum current is generally accepted as the EARTH fault level for an out of zone fault. Although a phase-
phase or 3-phase fault may have a higher fault current, the fault current for these faults will return locally in a
parallel path in the opposite direction i.e. in the other phase(s). With an earth fault, the return path may be distant
or non-parallel with the pilot such that the net current which couples to the pilot can be considered maximum for
the earth fault. The through fault current level is used in combination with the total feeder length as a worst case
scenario because although an internal fault may have a greater fault current, the parallel path will be shorter by
definition.
1.6.3 Pilot Cables
The above considerations of insulation and balance between cores, it is evident that pilot cables for use with pilot
wire current differential feeder protection are required to have special consideration when long lengths and high
fault currents are involved. It is also apparent that the effects are not easily analysed or modelled and thus in-
service experience is the most reliable basis in deciding which types of pilot will be satisfactory.
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7PG2113/4/5/6 Solkor Applications Guide
The UK has vast experience of the use of pilot wire differential feeder protection and the UK supply industry
specification on multipair cables, ESI Standard 09-6 is therefore particularly applicable as a reference for pilot
wire requirements.
It should be noted that the voltage between cores in the pilots is limited by the non-linear resistors which are
connected across the summation transformers in the Solkor relays at the ends. Also note that any induced
voltage will be at an equal level per unit length in all cores and screen. Thus it is possible to use pilots with 500v
grade insulation between cores and core to screen. The 5 or 15kV insulation requirement exists only between
‘internal cores and screen’ to the local earth. Similar considerations should be observed at any cable terminations
where standard 500v terminals can be used but the whole terminal block should be mounted on an insulating
baseplate to comply with insulation requirements to the local ground. Terminals should be shrouded and clearly
marked since during a system fault (included a fault on any parallel feeder, not only the protected circuit) the
induced voltage may pose a serious risk to health. Inside of the protection panel, the insulation to local earth and
segregation of wiring for health and safety purposes may be more easily achieved by the use of separate cable
trunking which can be routed independently and clearly marked rather than by the use of special cabling inside of
the panel. Special precautions will be required when terminating or handling pilot connections.
Pilot inter-core capacitance has the effect of shunting the relays in the current balance scheme. As the
capacitance increases a point is reached where the shunt impedance has a significant effect on the relay settings.
This produces a maximum limit for pilot capacitance which can be used with the relay. With the relays in the
Solkor R connection mode the pilot capacitance maximum limit is 2.5μF and with the Solkor Rf connection mode
this limit is 0.8μF. These limits can be increased for the Solkor Rf mode by the use of transformer tappings if the
15kV isolation transformers are used. The limits are 1μF, 2μF and 4μF which impose accompanying pilot LOOP
resistance limits of 1760Ω, 880Ωand 440Ωrespectively.
The pilot resistance is used in conjunction with settable padding resistance to achieve the stability biasing of the
relay. The padding resistance must be set in series with the pilot resistance to achieve a standard value. There is
therefore a maximum value for the pilot resistance for which the padding should be set to zero. The maximum
value of pilot LOOP resistance for the Solkor R mode is 1000Ωand for the Solkor Rf mode the maximum LOOP
resistance is 2000Ω.When 15kV isolation transformers in the Rf mode the maximum LOOP resistance
will be reduced to 1760Ωto compensate for the transformer winding resistance and if the transformer taps
are used to compensate for the effects of pilot capacitance the maximum LOOP resistance is reduced further to
values of, 880Ωand 440Ωdepending on the tap used. The actual pilot resistance must be referred through
the transformer at the chosen tap to give an equivalent pilot resistance value to which the padding
should be added.
Thus the padding resistance R = (Sv-Rp)/(2T)
Where Rp = Pilot LOOP resistance
Sv = standard value
=1000Ωfor Solkor R mode (T=1)
=2000Ωfor 5kV Solkor Rf mode (without transformers) (T=1)
=1760Ωfor Solkor Rf with 15kV transformers using tap 1 (T=1)
=880Ωfor Solkor Rf with 15kV transformers using tap 0.5 (T=0.5)
=440Ωfor Solkor Rf with 15kV transformers using tap 0.25 (T=0.25)
1.6.4 Pilot Supervision
Pilot supervision is used to detect failure of the pilot connection. Open circuit Pilots will lead to a loss of the
balance current from the remote end which will tend towards a differential trip condition. Pilot Supervision is often
applied as standard with the Solkor system but may be considered unnecessary at lower voltages or in an
interconnected system where unnecessary tripping of an un-faulted feeder may be tolerated due to limited
consequences in terms of loss of supply and relatively low probability of pilot damaged or failure when compared
to the additional equipment cost.
The Pilot Supervision system uses DC injection which cannot pass through a transformer. For this reason the
Pilot Supervision must be applied at the pilot side of the 15kV isolation transformers if fitted and therefore the
devices must have an isolation level to suit. The Send End unit and B75 Receive End must have 15kV insulation.
The B22 Supervision Relay and B74 Repeat Relay are not connected to the pilots directly and no special isolation
requirements apply to these devices.
1.6.5 Injection Intertripping
Injection Intertripping is generally difficult to apply successfully in conjunction with Overcurrent Guard relays since
the remote Guard relay will block operations resulting from intertrip injection if the remote end CT current is below
the Guard setting.
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7PG2113/4/5/6 Solkor Applications Guide
Injection intertripping is used to force the remote end circuit breaker to trip for local protection operation. This is
generally started by protection other than the Solkor system since a differential protection system will generally
trip on differential current at both ends regardless of the local current level.
1.6.6 Capacitive Charging Currents
Significant electrical capacitance exists between HV primary conductors and the adjacent earth such that a
capacitive charging current will exist with any energised line. The level of current is dependent on the system
voltage, the feeder length and the construction including materials and proximity of earthed conductors. The
highest levels are found in separate phase, individually screened and armoured conductors with lowest levels
found on overhead line feeders. These currents are generally supplied from one end only as balanced 3 phase
and as such constitute a differential current to the relays but is usually significantly lower than relay 3P setting.
During out of zone earth faults however, the voltage on the faulted phase may be significantly depressed such
that the charging current is reduced. The Solkor summation transformer will measure charging current on two
phases only and interpret this as a residual differential current for which relay settings are significantly lower than
for 3P balanced differential current. This issue is compounded in systems which are not solidly earthed because
the unfaulted phase voltage may increase, leading to increased charging current on these phases, during an
earth fault. The transient switching of charging current limits the maximum charging current to 1/3 of the most
sensitive earth fault setting for solidly earthed systems or 1/9 of the most sensitive earth fault setting for
resistance earthed systems.
On higher voltage systems, where separate single phase cables are more commonly used and feeders are
generally longer it is common to find phase segregated Solkor Rf systems where 3 separate Solkor relays are
fitted at each end, each connected to a separate pairs of pilots with one phase of the system CT connected to
each relay. This avoids the problem of summation of charging currents.
1.6.7 N/N1 Setting
The N1 tap can be used to increase the relay sensitivity to earth faults by lowering settings for these faults without
affecting the phase fault settings. This may be particularly desirable for the 15kV scheme where all settings are
naturally raised by the increase in energy required to drive the additional isolation transformers. It must be noted
that the use of the N1 tap will increase the burden on the CT and therefore should only be used if the CT knee
point voltage Vk easily exceeds the minimum requirements stated below, which is often the case with modern
CTs. Prior to the introduction of cold rolled iron in CT design, the CT magnetising current effects could cancel out
any reduction in setting by increasing the excitation currents required at the higher level of relay burden. Care
should be taken when applying the N1 tap to older designs of CT with limited Vk.
The Primary in Zone Capacitance may also limit the use of the N1 tap as loss of charging current may lead to
mal-operation at the lower earth fault setting as described above.
1.6.8 In-Zone Tapped Load (Bleed-Off)
The relay is able to tolerate a limited amount of tapped off balanced load within the zone of protection
based on the relatively insensitive level of fault setting for balanced 3P differential current. The typical
setting is 72% of rated current for 3P faults or differential load current. To allow for switching transients
of the tapped load a factor of 3 is advisable. The steady state feeder charging current and CT
inaccuracy will also erode the stability margin resulting in a maximum bleed off of 10-20% of rated
load current. Zero sequence infeed during out of zone earth faults from any transformer connected at
the tapping point must be less than the minimum earth fault sensitivity of the relay at the feeder end. If
a 20% tap off consists of a single large transformer, time lag relays may be required between the Solkor
trip contact and the CB coil to improve stability by allowing for inrush conditions due transformer excitation.
If the feeder is teed at the substation, with an additional CT fitted to the tee-off, the two CTs should be connected
in parallel. To minimise excitation caused by transient spill current the CTs should be connected by the shortest
electrical path. Care should be taken in CT specification to ensure that CT mismatch or saturation is not
significant for the out of zone fault path where the fault current is not limited by the protected impedance. Fault
current passing in and out of the paralleled CTs will fail to cancel if the CTs are mismatched or if saturation occurs
to different extents. This current may be higher than the through fault level upon which the CTs are usually sized.
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7PG2113/4/5/6 Solkor Applications Guide
Section 2: Additional Functions
2.1 Multiple Settings Groups
Alternate settings groups can be used to reconfigure the relay during significant changes to system conditions
e.g.
Primary plant switching in/out.
Summer/winter or day/night settings.
Switchable earthing connections.
Loss of Grid connection (see below)
RADIAL SUBSTATION
Start
generators
Select alternate
settings group
Local
Generation
Industrial system draws power from grid
system during normal operation
Relays normally use settings group 1
On loss of mains:
Local generation switched in.
Non essential loads tripped
Relays on essential circuits switched to
settings group 2 to reflect new load and
fault currents
Non-essential
loads
Trip non-essential loads
Figure 2.1-1 Example Use of Alternative Settings Groups
The Current Differential protection has fixed settings which cannot be adjusted by settings groups.
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2.2 Binary Inputs
Each Binary Input (BI) can be programmed to operate one or more of the relay functions, LEDs or output relays.
These could be used to bring such digital signals as Inhibits for protection elements, the trip circuit supervision
status, autoreclose control signals etc. into the Relay.
2.2.1 Alarm and Tripping Inputs
A common use of binary inputs is to provide indication of alarm or fault conditions e.g. transformer Buchholz Gas
or Buchholz Surge conditions. The Binary Inputs are mapped to LED(s), waveform storage trigger and binary
outputs. Note that transformer outputs which require high speed tripping, such as a Buchholz Surge, should be
wired to a binary input to provide LED indication and also have a parallel connection wired to directly trip the
circuit via a blocking diode, see fig. 1.2-1:
Figure 2.2-1 Example of Transformer Alarm and Trip Wiring
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2.2.2 The Effects of Capacitance Current
The binary inputs have a low minimum operate current and may be set for instantaneous operation. Consideration
should be given to the likelihood of mal-operation due to capacitance current. Capacitance current can flow
through the BI for example if an earth fault occurs on the dc circuits associated with the relay. The binary inputs
will be less likely to mal-operate if they:
1 Have both the positive and negative switched (double-pole switched).
2 Do not have extensive external wiring associated with them e.g. if the wiring is confined to the
relay room.
Where a binary input is both used to influence a control function (e.g. provide a tripping function) and it is
considered to be susceptible to mal-operation the external circuitry can be modified to provide immunity to such
disturbances, see fig 1.2-2.
2.2.3 AC Rejection
The default pick-up time delay of 20ms provides immunity to ac current e.g. induced from cross site wiring.
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Figure 2.2-2 Binary Input Configurations Providing Compliance with EATS 48-4 Classes ESI 1 and ESI 2
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2.3 Binary Outputs
Binary Outputs are mapped to output functions by means of settings. These could be used to bring out such
digital signals as trips, a general pick-up, plant control signals etc.
All Binary Outputs are Trip rated
Each can be defined as Self or Hand Reset. Self-reset contacts are applicable to most protection applications.
Hand-reset contacts are used where the output must remain active until the user expressly clears it e.g. in a
control scheme where the output must remain active until some external feature has correctly processed it.
Notes on Self Reset Outputs
With a failed breaker condition the relay may remain operated until current flow in the primary system is
interrupted by an upstream device. The relay will then reset and attempt to interrupt trip coil current flowing
through an output contact. Where this level is above the break rating of the output contact an auxiliary relay with
heavy-duty contacts should be utilised.
2.4 LEDS
In the Output Configuration menu LEDs can be mapped to output functions by means of settings. These could be
used to display such digital signals as trips, a general pick-up, plant control signals etc.
Each LED can be defined as Self or Hand Reset. Hand reset LEDs are used where the user is required to
expressly acknowledge the change in status e.g. critical operations such as trips or system failures. Self-reset
LEDs are used to display features which routinely change state, such as Circuit-Breaker open or close.
The status of hand reset LEDs is retained in capacitor-backed memory in the event of supply loss.
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©2010 Siemens Protection Devices Limited Chapter 7 Page 19 of 49
Section 3: Protection Functions
3.1 Time delayed overcurrent (51/51G/51N)
The 51-n characteristic element provides a number of time/current operate characteristics. The element can be
defined as either an Inverse Definite Minimum Time Lag (IDMTL) or Definite Time Lag (DTL) characteristic. If an
IDMTL characteristic is required, then IEC, ANSI/IEEE and a number of manufacturer specific curves are
supported.
IDMTL characteristics are defined as “Inverse” because their tripping times are inversely proportional to the Fault
Current being measured. This makes them particularly suitable to grading studies where it is important that only
the Relay(s) closest to the fault operate. Discrimination can be achieved with minimised operating times.
To optimise the grading capability of the relay additional time multiplier, ‘Follower DTL’ (Fig. 2.1-1) or ‘Minimum
Operate Time’ (Fig. 2.1-2) settings can be applied.
0.01
0.10
1.00
10.00
100.00
1000.00
1 10 100 1000
Current (x Is)
Operating Time (Seconds
)
0.01
0.10
1.00
10.00
100.00
1000.00
1 10 100 1000
Current (x Is)
Operating Time (Seconds
)
Figure 3.1-1 IEC NI Curve with Time ultiplier and Follower DTL Applied M

7PG2113/4/5/6 Solkor Applications Guide
0.01
0.10
1.00
10.00
100.00
1000.00
1 10 100 1000
Current (x Is)
Operating Time (Seconds
)
Figure 3.1-2 IEC NI Curve with Minimum Operate Time Setting Applied
To increase sensitivity, dedicated Earth fault elements are used. There should be little or no current flowing to
earth in a healthy system so such relays can be given far lower pick-up levels than relays which detect excess
current ( > load current) in each phase conductor. Such dedicated earth fault relays are important where the fault
path to earth is a high-resistance one (such as in highly arid areas) or where the system uses high values of
earthing resistor / reactance and the fault current detected in the phase conductors will be limited.
3.1.1 Selection of Overcurrent Characteristics
Each pole has two independent over-current characteristics. Where required the two curves can be used:
To produce a composite curve
To provide a two stage tripping scheme
Where one curve is to be directionalised in the forward direction the other in the reverse direction.
The characteristic curve shape is selected to be the same type as the other relays on the same circuit or to grade
with items of plant e.g. fuses or earthing resistors.
The application of IDMTL characteristic is summarised in the following table:
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