Siemens Argus 7SR21 User manual

7SR21 & 7SR22 Argus Applications Guide
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©2010 Siemens Protection Devices Limited
7SR21 Non-Directional
7SR22 Directional
Overcurrent Relay
Document Release History
This document is issue 2010/05. The list of revisions up to and including this issue is:
2010/05 Typographical revisions
2010/02 Document reformat due to rebrand
2009/09 Third Issue. Software revision 2435H80004/5 R4b-4
2008/07 Second issue. Software revision 2435H80004/5 R3d-3.
2008/03 First issue
Software Revision History
2009/09 2435H80004/5 R4b-4 CTS-I Supervision. Undercurrent 37G & 37SEF. Vx U/O Voltage. 46BC
U/C. Comms Settings. Waveform Storage Settings. Fault Storage
Settings. Energy Storage. Trip test function. Local/Remote modes.
Settings ranges extended. Protocol changes.
2008/07 2435H80004/5R3d-3 Demand records. Optional DNP3.0 data comms.
2008/03 2435H80004/5R2c-2b First Release

7SR21 & 7SR22 Argus Applications Guide
Contents
Document Release History....................................................................................................................1
Software Revision History.....................................................................................................................1
Contents..................................................................................................................................................2
Section 1: Common Functions .............................................................................................................4
1.1 Multiple Settings Groups...........................................................................................................4
1.2 Binary Inputs .............................................................................................................................5
1.3 Binary Outputs ..........................................................................................................................8
1.4 LEDs .........................................................................................................................................8
Section 2: Protection Functions.........................................................................................................10
2.1 Time delayed overcurrent (51/51G/51N) ................................................................................10
2.1.1 Selection of Overcurrent Characteristics ...................................................................11
2.1.2 Reset Delay................................................................................................................12
2.2 Voltage dependent overcurrent (51V).....................................................................................13
2.3 Cold Load Settings (51c) ........................................................................................................13
2.4 Instantaneous Overcurrent (50/50G/50N) ..............................................................................14
2.4.1 Blocked Overcurrent Protection Schemes.................................................................14
2.5 Sensitive Earth-fault Protection (50SEF) ................................................................................16
2.6 Directional Protection (67) ......................................................................................................17
2.7 Directional Earth-Fault (50/51G, 50/51N, 51/51SEF) .............................................................20
2.8 High Impedance Restricted Earth Fault Protection (64H) ......................................................21
2.9 Negative Phase Sequence Overcurrent (46NPS) ..................................................................23
2.10 Undercurrent (37)....................................................................................................................23
2.11 Thermal Overload (49)............................................................................................................23
2.12 Under/Over Voltage Protection (27/59) ..................................................................................24
2.13 Neutral Overvoltage (59N) ......................................................................................................25
2.13.1 Application with Capacitor Cone Units.......................................................................26
2.13.2 Derived NVD Voltage.................................................................................................26
2.14 Negative Phase Sequence Overvoltage (47) .........................................................................26
2.15 Under/Over Frequency (81) ....................................................................................................27
Section 3: CT Requirements ...............................................................................................................28
3.1 CT Requirements for Overcurrent and Earth Fault Protection ...............................................28
3.1.1 Overcurrent Protection CTs .......................................................................................28
3.1.2 Earth Fault Protection CTs.........................................................................................28
3.2 CT Requirements for High Impedance Restricted Earth Fault Protection..............................28
Section 4: Control Functions..............................................................................................................29
4.1 Auto-reclose Applications .......................................................................................................29
4.1.1 Auto-Reclose Example 1............................................................................................30
4.1.2 Auto-Reclose Example 2 (Use of Quicklogic with AR) ..............................................31
4.2 Quick Logic Applications.........................................................................................................32
4.2.1 Auto-Changeover Scheme Example..........................................................................32
Section 5: Supervision Functions ......................................................................................................33
5.1 Circuit-Breaker Fail (50BF) .....................................................................................................33
5.1.1 Settings Guidelines ....................................................................................................33
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©2010 Siemens Protection Devices Limited Chapter 7 Page 3 of 39
5.2 Current Transformer Supervision (60CTS).............................................................................35
5.3 Voltage Transformer Supervision (60VTS).............................................................................36
5.4 Trip-Circuit Supervision (74TCS)............................................................................................37
5.4.1 Trip Circuit Supervision Connections.........................................................................37
5.5 Inrush Detector (81HBL2) .......................................................................................................39
5.6 Broken Conductor / Load Imbalance (46BC)..........................................................................39
5.7 Circuit-Breaker Maintenance ..................................................................................................39
List of Figures
Figure 1.1-1 Example Use of Alternative Settings Groups ......................................................................4
Figure 1.2-1 Example of Transformer Alarm and Trip Wiring ..................................................................5
Figure 1.2-2 – Binary Input Configurations Providing Compliance with EATS 48-4 Classes
ESI 1 and ESI 2 ...................................................................................................................7
Figure 1.4-1 LED configuration via the LED Matrix tab............................................................................8
Figure 1.4-2 LED configuration via the Settings \ OUTPUT CONFIG \ LED CONFIG menu ..................9
Figure 2.1-1 IEC NI Curve with Time Multiplier and Follower DTL Applied ...........................................10
Figure 2.1-2 IEC NI Curve with Minimum Operate Time Setting Applied ..............................................11
Figure 2.1-3 Reset Delay .......................................................................................................................12
Figure 2.4-1 General Form of DTL Operate Characteristic....................................................................14
Figure 2.4-2 Blocking Scheme Using Instantaneous Overcurrent Elements .........................................15
Figure 2.5-1 Sensitive Earth Fault Protection Application......................................................................16
Figure 2.6-1 Directional Characteristics ................................................................................................17
Figure 2.6-2 Phase Fault Angles............................................................................................................17
Figure 2.6-3 Application of Directional Overcurrent Protection..............................................................18
Figure 2.6-4 Feeder Fault on Interconnected Network ..........................................................................19
Figure 2.7-1 Earth Fault Angles .............................................................................................................20
Figure 2.8-1 Balanced and Restricted Earth-fault protection of Transformers ....................................21
Figure 2.8-2 Composite Overcurrent and Restricted Earth-fault Protection .........................................22
Figure 2.11-1 Thermal Overload Heating and Cooling Characteristic .............................................23
Figure 2.13-1 NVD Application...............................................................................................................25
Figure 2.13-2 NVD Protection Connections ...........................................................................................25
Figure 2.15-1 Load Shedding Scheme Using Under-Frequency Elements...........................................27
Figure 4.1-1 Sequence Co-ordination ....................................................................................................29
Figure 4.1-2 Example of Logic Application.............................................................................................31
Figure 4.2-1 Example Use of Quick Logic..............................................................................................32
Figure 5.1-1 - Circuit Breaker Fail ..........................................................................................................33
Figure 5.1-2 - Single Stage Circuit Breaker Fail Timing.........................................................................34
Figure 5.1-3 - Two Stage Circuit Breaker Fail Timing............................................................................34
Figure 5.4-1:Trip Circuit Supervision Scheme 1 (H5) ............................................................................37
Figure 5.4-2:Trip Circuit Supervision Scheme 2 (H6) ............................................................................38
Figure 5.4-3:Trip Circuit Supervision Scheme 3 (H7) ............................................................................38
List of Tables
Table 2-1 Application of IDMTL Characteristics……………………………………………………..12
Table 5-2 Determination of VT Failure (1 or 2 Phases) …………………………………………….36
Table 5-3 Determination of VT Failure (3 Phases) ………………………………………………….36
Table 5-4 Magnetic Inrush Bias………………………………………………………………………..39

7SR21 & 7SR22 Argus Applications Guide
Section 1: Common Functions
1.1 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 1.1-1 Example Use of Alternative Settings Groups
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7SR21 & 7SR22 Argus Applications Guide
1.2 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.
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 1.2-1 Example of Transformer Alarm and Trip Wiring
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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.
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 1.2-2 – Binary Input Configurations Providing Compliance with EATS 48-4 Classes ESI 1 and ESI 2
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1.3 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.
Case contacts 26 and 27 will automatically short-circuit when the relay is withdrawn from the case. This can be
used to provide an alarm that the Relay is out of service.
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.
1.4 LEDs
Output-function LEDs are 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.
User Defined Function Key LEDs are used to indicate the status of Function Key operation. These do not relate
directly to the operation of the Function Key but rather to its consequences. If a Function Key is depressed to
close a Circuit-Breaker, the associated LED would show the status of the Circuit-Breaker closed Binary Input.
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.
Each LED can be assigned as red, yellow or green in colour. There are two methods for doing this: -
1) In the LED Matrix tab, to assign the LED as a red colour select a box on the red row. To assign the
LED as a green colour select a box on the green row. To assign the LED as a yellow colour, select
boxes on both the red and green rows.
NB: If there are no boxes selected the LED will not illuminate.
Figure 1.4-1 LED configuration via the LED Matrix tab
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7SR21 & 7SR22 Argus Applications Guide
2) In the OUTPUT CONFIG\LED CONFIG menu in the Settings tab, to assign the required LED as a
particular colour, either red or green, type the LED number in the appropriate row. To assign the
required LED as a yellow colour, type the LED number in both red and green rows.
NB: If a LED number is not assigned that particular LED will not illuminate.
Figure 1.4-2 LED configuration via the Settings \ OUTPUT CONFIG \ LED CONFIG menu
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7SR21 & 7SR22 Argus Applications Guide
Section 2: Protection Functions
2.1 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 2.1-1 IEC NI Curve with Time Multiplier and Follower DTL Applied
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7SR21 & 7SR22 Argus 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 2.1-2 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.
2.1.1 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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7SR21 & 7SR22 Argus Applications Guide
OC/EF Curve Characteristic Application
IEC Normal Inverse (NI)
ANSI Moderately Inverse (MI)
Generally applied
IEC Very Inverse (VI)
ANSI Very Inverse (VI)
Used with high impedance paths where there is a significant difference
between fault levels at protection points
IEC Extreme Inversely (EI)
ANSI Extremely Inverse (EI)
Grading with Fuses
IEC Long Time Inverse (LTI) Used to protect transformer earthing resistors having long withstand times
Recloser Specific Use when grading with specific recloser
Table 2-1 Application of IDMTL Characteristics
2.1.2 Reset Delay
The increasing use of plastic insulated cables, both conventionally buried and aerial bundled conductors, have
given rise to the number of flashing intermittent faults on distribution systems. At the fault position, the plastic
melts and temporarily reseals the faulty cable for a short time after which the insulation fails again. The same
phenomenon has occurred in compound-filled joint boxes or on ‘clashing’ overhead line conductors. The
repeating process of the fault can cause electromechanical disc relays to “ratchet” up and eventually trip the faulty
circuit if the reset time of the relay is longer than the time between successive faults.
To mimic an electromechanical relay the relay can be user programmed for an ANSI DECAYING characteristic
when an ANSI operate characteristic is applied. Alternatively a DTL reset (0 to 60 seconds) can be used with
other operate characteristics.
For protection of cable feeders, it is recommended that a 60 second DTL reset be used.
On overhead line networks, particularly where reclosers are incorporated in the protected system, instantaneous
resetting is desirable to ensure that, on multiple shot reclosing schemes, correct grading between the source
relays and the relays associated with the reclosers is maintained.
Figure 2.1-3 Reset Delay
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7SR21 & 7SR22 Argus Applications Guide
2.2 Voltage dependent overcurrent (51V)
Reduced voltage can indicate a fault on the system, it can be used to make the 51 elements more sensitive.
Typically Voltage Dependent Over-current (51V) is applied to:
Transformer Incomers: Where the impedance of the transformer limits fault current the measured
voltage level can be used to discriminate between load and fault current.
Long lines: Where the impedance of the line limits fault current the measured voltage level can be used
to discriminate between load and fault current.
Generator circuits: When a Generator is subjected to a short circuit close to its terminals the short-
circuit current follows a complex profile. After the initial "sub-transient" value, generally in the order of 7
to 10 times full load current, it falls rapidly (around 10 to 20ms) to the "transient" value. This is still about
5 to 7 times full load and would be sufficient to operate the protection's over-current elements. However
the effect on armature reactance of the highly inductive short-circuit current is to increase significantly
the internal impedance to the synchronous reactance value. If the Automatic Voltage Regulation (AVR)
system does not respond to increase the excitation, the fault current will decay over the next few
seconds to a value below the full load current. This is termed the steady state fault current, determined
by the Generator's synchronous reactance (and pre-fault excitation). It will be insufficient to operate the
protection's over-current elements and the fault will not be detected. Even if AVR is active, problems may
still be encountered. The AVR will have a declared minimum sustained fault current and this must be
above the protection over-current settings. Close-in short circuit faults may also cause the AVR to reach
its safety limits for supplying maximum excitation boost, in the order of several seconds, and this will
result in AVR internal protection devices such as diode fuses to start operating. The generator excitation
will then collapse, and the situation will be the same as when no AVR was present. The fault may again
not be detected.
Current grading remains important since a significant voltage reduction may be seen for faults on other parts of
the system. An inverse time operating characteristic must therefore be used.
The VDO Level - the voltage setting below which the more sensitive operating curve applies - must be set low
enough to discriminate between short-circuits and temporary voltage dips due to overloads. However, it must also
be high enough to cover a range of voltage drops for different circuit configurations, from around 0.6Vn to almost
zero. Typically it will be set in the range 0.6 to 0.8Vn.
2.3 Cold Load Settings (51c)
Once a Circuit-Breaker has been open for a period of time ed, higher than normal levels of load current may flow
following CB re-closure e.g. heating or refrigeration plant. The size and duration of this current is dependent upon
the type of load and the time that the CB is open.
The feature allows the relay to use alternative Shaped Overcurrent (51c) settings when a Cold Load condition is
identified. The cold load current and time multiplier settings will normally be set higher than those of the normal
overcurrent settings.
The relay will revert to its usual settings (51-n) after elapse of the cold load period. This is determined either by a
user set delay, or by the current in all 3-phases falling below a set level (usually related to normal load levels) for
a user set period.
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7SR21 & 7SR22 Argus Applications Guide
2.4 Instantaneous Overcurrent (50/50G/50N)
Each instantaneous element has an independent setting for pick-up current and a follower definite time lag (DTL)
which can be used to provide time grading margins, sequence co-ordination grading or scheme logic. The
“instantaneous” description relates to the pick-up of the element rather than its operation.
Operating time
Figure 2.4-1 General Form of DTL Operate Characteristic
Instantaneous elements can be used in current graded schemes where there is a significant difference between
the fault current levels at different relay point. The Instantaneous element is set to pick up at a current level above
the maximum Fault Current level at the next downstream relay location, and below its own fault current level. The
protection is set to operate instantaneously and is often termed ‘Highset Overcurrent’. A typical application is the
protection of transformer HV connections – the impedance of the transformer ensuring that the LV side has a
much lower level of fault current.
The 50-n elements have a very low transient overreach i.e. their accuracy is not appreciably affected by the initial
dc offset transient associated with fault inception.
2.4.1 Blocked Overcurrent Protection Schemes
A combination of instantaneous and DTL elements can be used in blocked overcurrent protection schemes.
These protection schemes are applied to protect substation busbars or interconnectors etc. Blocked overcurrent
protection provides improved fault clearance times when compared against normally graded overcurrent relays.
The blocked overcurrent scheme of busbar protection shown in Figure 2.2-2 illustrates that circuit overcurrent and
earth fault protection relays can additionally be configured with busbar protection logic.
The diagram shows a substation. The relay on the incomer is to trip for busbar faults (F1) but remain inoperative
for circuit faults (F2).
In this example the overcurrent and earth fault settings for the incomer 50-1 element are set to below the relevant
busbar fault levels. 50-1 time delay is set longer than it would take to acknowledge receipt of a blocking signal
from an outgoing circuit.
Close up faults on the outgoing circuits will have a similar fault level to busbar faults. As the incomer 50-1
elements would operate for these faults it is necessary to provide a blocking output from the circuit protections.
The 50-1 elements of the output relays are given lower current settings than the incomer 50-1 settings, the time
delay is set to 0ms. The output is mapped to a contact. The outgoing relay blocking contacts of all circuits are
wired in parallel and this wiring is also connected to a BI on the incomer relay. The BI on the incomer relay is
mapped to block its 50-1 element.
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7SR21 & 7SR22 Argus Applications Guide
Figure 2.4-2 Blocking Scheme Using Instantaneous Overcurrent Elements
Typically a time delay as low as 50ms on the incomer 50-1 element will ensure that the incomer is not tripped for
outgoing circuit faults. However, to include for both equipment tolerances and a safety margin a minimum time
delay of 100ms is recommended.
This type of scheme is very cost effective and provides a compromise between back-up overcurrent busbar
protection and dedicated schemes of busbar protection.
Instantaneous elements are also commonly applied to autoreclose schemes to grade with downstream circuit
reclosers and maximise the probability of a successful auto-reclose sequence – see section 4.
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7SR21 & 7SR22 Argus Applications Guide
2.5 Sensitive Earth-fault Protection (50SEF)
Earth fault protection is based on the assumption that fault current levels will be limited only by the earth fault
impedance of the line and associated plant. However, it may be difficult to make an effective short circuit to earth
due to the nature of the terrain e.g. dry earth, desert or mountains. The resulting earth fault current may therefore
be limited to very low levels.
Sensitive earth fault (SEF) protection is used to detect such faults. The RM range of relays have a low burden, so
avoiding unacceptable loading of the CTs at low current settings.
SEF provides a backup to the main protection. A DTL characteristic with a time delay of several seconds is
typically applied ensuring no interference with other discriminative protections. A relatively long time delay can be
tolerated since fault current is low and it is impractical to grade SEF protection with other earth fault protections.
Although not suitable for grading with other forms of protection SEF relays may be graded with each other.
Where very sensitive current settings are required then it is preferable to use a core balance CT rather than wire
into the residual connection of the line CTs. The turns ratio of a core balance CT can be much smaller than that of
phase conductors as they are not related to the rated current of the protected circuit. Since only one core is used,
the CT magnetising current losses are also reduced by a factor of 3.
Circuit 1 Circuit 2 Circuit 3
Core
Balance
CT
INCOMER
Figure 2.5-1 Sensitive Earth Fault Protection Application
There are limits to how sensitive an SEF relay may be set since the setting must be above any line charging
current levels that can be detected by the relay. On occurrence of an out of zone earth fault e.g. on circuit 3 the
elevation of sound phase voltage to earth in a non-effectively earthed system can result in a zero sequence
current of up 3 times phase charging current flowing through the relay location.
The step change from balanced 3-phase charging currents to this level of zero sequence current includes
transients. It is recommended to allow for a transient factor of 2 to 3 when determining the limit of charging
current. Based on the above considerations the minimum setting of a relay in a resistance earthed power system
is 6 to 9 times the charging current per phase.
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7SR21 & 7SR22 Argus Applications Guide
2.6 Directional Protection (67)
Each overcurrent stage can operate for faults in either forward or reverse direction. Convention dictates that
forward direction refers to power flow away from the busbar, while reverse direction refers to power flowing
towards the busbar.
The directional phase fault elements, 67/50 and 67/51, work with a Quadrature Connection to prevent loss of
polarising quantity for close-in phase faults. That is, each of the current elements is directionalised by a voltage
derived from the other two phases.
This connection introduces a 90° Phase Shift (Current leading Voltage) between reference and operate quantities
which must be allowed for in the Characteristic Angle setting. This is the expected fault angle, sometimes termed
the Maximum Torque Angle (MTA) as an analogy to older Electro-mechanical type relays
Example: Expected fault angle is -30º (Current lagging Voltage) so set Directional Angle to: +90° -30° = +60°.
A fault is determined to be in the selected direction if its phase relationship lies within a quadrant +/- 85° either
side of the Characteristic Angle setting.
Figure 2.6-1 Directional Characteristics
A number of studies have been made to determine the optimum MTA settings e.g. W.K Sonnemann’s paper “A
Study of Directional Element Connections for Phase Relays”. Figure 2 10 shows the most likely fault angle for
phase faults on Overhead Line and Cable circuits.
V
Transformer Feeders
(Cable Circuits)
-45
0
MTA
Current lagging
Voltage
Plain Feeders
(Overhead Lines)
-30
0
MTA
I
V
I
Figure 2.6-2 Phase Fault Angles
Current
- operating
quantity Characteristic
Angle
Volts
- polarising
quantity
OPERATING
BOUNDARY
(Zero Torque Line)
OPERATE
INHIBIT
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Directional overcurrent elements allow greater fault selectivity than non-directional elements for interconnected
systems where fault current can flow in both directions through the relaying point. Consider the network shown in
fig. 2.6-3.
The Circuit breakers at A, B, E and G have directional overcurrent relays fitted since fault current can flow in both
directions at these points. The forward direction is defined as being away from the busbar and against the
direction of normal load current flow. These forward looking IDMTL elements can have sensitive settings applied
i.e. low current and time multiplier settings. Note that 7SR22 relays may be programmed with forward, reverse
and non-directional elements simultaneously when required by the protection scheme.
Load
A
C
E
B
D
G
Figure 2.6-3 Application of Directional Overcurrent Protection
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7SR21 & 7SR22 Argus Applications Guide
Load
A
C
E
B
D
G
Fault 1
Figure 2.6-4 Feeder Fault on Interconnected Network
Considering the D-G feeder fault shown in fig. 2.6-4: the current magnitude through breakers C and D will be
similar and their associated relays will similar prospective operate times. To ensure that only the faulted feeder is
isolated G FWD must be set to be faster than C. Relay G will thus Trip first on FWD settings, leaving D to operate
to clear the fault. The un-faulted Feeder C-E maintains power to the load.
Relays on circuits C and D at the main substation need not be directional to provide the above protection scheme.
However additional directional elements could be mapped to facilitate a blocked overcurrent scheme of busbar
protection.
At A and B, forward looking directional elements enable sensitive settings to be applied to detect transformer
faults whilst reverse elements can be used to provide back-up protection for the relays at C and D.
By using different settings for forward and reverse directions, closed ring circuits can be set to grade correctly
whether fault current flows in a clockwise or counter clockwise direction i.e. it may be practical to use only one
relay to provide dual directional protection.
2 Out of 3 Logic
Sensitive settings can be used with directional overcurrent relays since they are directionalised in a way which
opposes the flow of normal load current i.e. on the substation incomers as shown on fig. 2.6-4. However on
occurrence of transformer HV or feeder incomer phase-phase faults an unbalanced load current may still flow as
an un balanced driving voltage is present. This unbalanced load current during a fault may be significant where
sensitive overcurrent settings are applied - the load current in one phase may be in the operate direction and
above the relay setting.
Where this current distribution may occur then the relay is set to CURRENT PROTECTION>PHASE
OVERCURRENT> 67 2-out-of-3 Logic = ENABLED
Enabling 2-out-of-3 logic will prevent operation of the directional phase fault protection for a single phase to earth
fault. Dedicated earth-fault protection should therefore be used if required.
©2010 Siemens Protection Devices Limited Chapter 7 Page 19 of 39

7SR21 & 7SR22 Argus Applications Guide
2.7 Directional Earth-Fault (50/51G, 50/51N, 51/51SEF)
The directional earth-fault elements, either measure directly or derive from the three line currents the zero
sequence current (operate quantity) and compare this against the derived zero phase sequence voltage
(polarising quantity). Section 1 of the Technical Manual ‘Description of Operation’ details the method of
measurement. The required setting is entered directly as dictated by the system impedances.
Example: Expected fault angle is -45° (i.e. residual current lagging residual voltage) therefore 67G Char Angle =
-45°
However directional earth elements can be selectable to use either ZPS or NPS Polarising. This is to allow for the
situation where ZPS voltage is not available; perhaps because a 3-limb VT is being used. Care must be taken as
the Characteristic Angle will change if NPS Polarising is used.
Once again the fault angle is completely predictable, though this is a little more complicated as the method of
earthing must be considered.
Figure 2.7-1 Earth Fault Angles
©2010 Siemens Protection Devices Limited Chapter 7 Page 20 of 39