Protection Guidelines
17 April 2012
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1
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Energy.
2011 ESSENTIAL ENERGY
17 APRIL 2012
ISSUE 4
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CONTENTS PAGE
1
INTRODUCTION ............................................................................................. 5
2
ACTIONS AND RESPONSIBILITIES ................................................................... 5
2.1
3
PROTECTION DESIGN .................................................................................... 6
3.1
4
5
Design.......................................................................................................... 6
SUBSTATION BATTERIES ................................................................................ 7
4.1
Protection Sensitivity...................................................................................... 7
4.2
Protection against Abnormal Operating Conditions ............................................. 7
4.3
Protection Selectivity ...................................................................................... 8
4.4
Fault Clearance Times .................................................................................... 8
4.5
Coordination of Protection Settings .................................................................. 8
4.6
Protection Flagging and Indication ................................................................... 8
4.7
Trip Supply Supervision Requirements .............................................................. 8
4.8
Trip Circuit Supervision .................................................................................. 8
PROTECTION SCHEMES .................................................................................. 8
5.1
Protection Scheme Selection ........................................................................... 9
5.2
Fault Clearance Times ...................................................................................10
5.3
Selection Requirements - General ...................................................................11
5.4
Transmission Plant ........................................................................................11
5.5
Subtransmission and Distribution Protection and Substation Plant .......................11
5.6
Main Protection ............................................................................................11
5.7
Backup Protection .........................................................................................12
5.8
Distribution Transformers ..............................................................................12
5.9
Capacitor Banks ...........................................................................................12
5.10
6
Role of Protection .......................................................................................... 5
5.9.1
Unbalance Protection ................................................................................ 12
5.9.2
Overcurrent Protection .............................................................................. 12
5.9.3
Reclose Inhibit ......................................................................................... 13
Circuit Breaker Fail .......................................................................................13
SETTING PHILOSOPHY – ZONE SUBSTATION SCHEMES.....................................13
6.1
Distance Schemes.........................................................................................13
6.1.1
Number of Zones ..................................................................................... 13
6.1.2
Quadrilateral Ground Protection ................................................................. 14
6.1.3
Zone 1 Protection ..................................................................................... 14
6.1.4
Zone 2 Protection ..................................................................................... 14
6.1.5
Zone 3 Protection ..................................................................................... 15
6.1.6
Mutual Coupling ....................................................................................... 16
6.1.7
Arcing Resistance / Infeed ......................................................................... 16
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6.1.8
Loss of Potential ....................................................................................... 17
6.1.9
Broken Conductor Detection ...................................................................... 17
6.2
Directional Overcurrent and Earth Fault ...........................................................17
6.3
Line Differential Protection and Communications Assisted Distance Schemes ........18
6.4
Busbar Protection .........................................................................................18
6.5
6.6
6.7
6.8
7
CEOP8002
6.4.1
Location of Busbar CT‟s ............................................................................. 18
6.4.2
High Impedance Busbar Protection ............................................................. 18
Transformer Protection ..................................................................................19
6.5.1
Transformer Differential Protection ............................................................. 19
6.5.2
Transformer Restricted Earth Fault Protection .............................................. 21
6.5.3
Transformer Thermal Protection ................................................................. 22
6.5.4
Transformer Mechanical Protection ............................................................. 23
6.5.5
Transformer High Voltage Overcurrent and Earth Fault Protection .................. 23
Distribution Busbar Protection ........................................................................24
6.6.1
Transformer Low Voltage Overcurrent and Earth Fault Protection ................... 24
6.6.2
Transformer Low Voltage Neutral Earth Fault Protection ................................ 24
6.6.3
Lower Voltage Busbar Protection Scheme .................................................... 25
6.6.4
Blocking Schemes for Distribution Busbar Speed Enhancement ...................... 25
Subtransmission Undervoltage and Underfrequency Protection ...........................26
6.7.1
Undervoltage Protection ............................................................................ 26
6.7.2
Underfrequency Protection ........................................................................ 26
Sub Transmission Automatic reclose ...............................................................26
6.8.1
Automatic Reclose Justification................................................................... 26
6.8.2
Subtransmission Feeders ........................................................................... 26
6.8.3
Subtransmission Transformers ................................................................... 27
6.8.4
Subtransmission Busbars .......................................................................... 27
6.8.5
Automatic Reclose Timing.......................................................................... 27
6.8.6
Automatic Reclose Attempts ...................................................................... 27
SETTING PHILOSOPHY – DISTRIBUTION SCHEMES ...........................................28
7.1
7.2
7.3
Distribution Feeder Protection within Zone Substations ......................................28
7.1.1
Feeder Overcurrent and Earth Fault Protection ............................................. 28
7.1.2
Feeder Sensitive Earth Fault (SEF) Protection .............................................. 31
7.1.3
Underfrequency Protection ........................................................................ 31
Shunt Capacitor Protection .............................................................................31
7.2.1
Capacitor Components and Types ............................................................... 31
7.2.2
Capacitor Protection ................................................................................. 32
7.2.3
Capacitor Overcurrent and Earth Fault Protection ......................................... 33
7.2.4
Capacitor Unbalance Protection .................................................................. 34
7.2.5
Capacitor Overvoltage Protection................................................................ 34
Frequency Injection System Protection ............................................................34
7.3.1
FI Set Overcurrent and Earth Fault Protection .............................................. 34
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7.4
7.5
7.6
CEOP8002
Distribution Automatic Reclose .......................................................................36
7.4.1
Automatic Reclose Justification................................................................... 36
7.4.2
Automatic Reclose Attempts ...................................................................... 36
7.4.3
Reclaim Time ........................................................................................... 37
Automatic Field Reclosers ..............................................................................38
7.5.1
O/C, E/F and SEF Protection on line Reclosers .............................................. 38
7.5.2
Coordination between Reclosers and Recloser in Series ................................. 39
7.5.3
Coordination between Recloser and Sectionaliser in Series ............................ 39
7.5.4
Coordination between Reclosers and Fuses in Series: .................................... 39
7.5.5
Coordination between Fuses and Downstream Reclosers ............................... 41
7.5.6
Basic Coordination Principles to be Observed ............................................... 41
7.5.7
Basic Guidelines for the Location of Reclosers: ............................................. 42
7.5.8
Application Rules for Reclosers ................................................................... 42
Line Fuses ...................................................................................................42
7.6.1
Fuse to Fuse Coordination ......................................................................... 43
7.6.2
Principles of Operation of Fuses .................................................................. 43
7.6.3
Grading of Fuse to Fuse of the Same Voltage ............................................... 44
7.6.4
Types of Distribution Fuses ........................................................................ 44
8
PROTECTION COORDINATION ........................................................................44
9
RECORDS ....................................................................................................44
10
HIGH VOLTAGE CUSTOMERS ..........................................................................45
11
GENERATORS ............................................................................................... 45
12
ATTACHMENT A – TOTAL FAULT CLEARING TIME CALCULATIONS, METHODS AND
TERMS ........................................................................................................46
13
REFERENCES................................................................................................ 47
14
REVISIONS ..................................................................................................47
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1
CEOP8002
INTRODUCTION
This Operational Procedure sets out the general requirements for protection systems
installed on Essential Energy‟s high voltage transmission, subtransmission and distribution
systems.
Distribution automatic reclose equipment is also included in this code of practice.
The guidelines in this document cover Essential Energy‟s Transmission (above 66kV),
Subtransmission (66kV, 33kV, 22kV), and Distribution high voltage systems (6.35kV, 6.6kV,
11kV, 22kV, 33kV, 12.7kV SWER, 19.1kV SWER).
This document does not preclude the installation or maintenance of protection that exceeds
the requirements of this Procedural Guideline; or protection that does not completely meet
the requirements of this Procedural Guideline where special considerations exist.
2
ACTIONS AND RESPONSIBILITIES
2.1
Role of Protection
While it is not possible to eliminate risk to personnel and livestock from power lines and
equipment energised at the voltages covered by this document, an important role of
protection equipment is to reduce the level of such risk to an acceptable minimum.
Protection equipment should be designed to detect and clear all faults on the high voltage
system rapidly while maintaining supply to the largest possible proportion of the electricity
supply system in a manner that avoids (wherever possible) danger to personnel or livestock
or damage to equipment.
Whenever possible all faults should be seen by a backup protection device as detailed within
this document.
Protection schemes applied to Essential Energy‟s high voltage system are not normally set
to protect against overload conditions unless specifically required.
To achieve this, the protection scheme must be designed to:
detect all possible faults that can occur within the protected zone
clear the fault as quickly as practical
discriminate (isolate the minimum proportion of the system consistent with clearing
the fault)
be reliable (operate when it is required to)
be secure (not operate when it is not required).
It is not always possible to achieve all these goals. In particular, the goals of reliability and
security can conflict.
HV Equipment must never be left energised without adequate protection. If in any instance
the normal protection equipment is out of service, the equipment must either:
be de-energised; or
be energised from a source that can provide adequate protection; or
be provided with a backup or alternative temporary protection.
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The Group Manager Technical Services and Protection Coordination Manager shall
be responsible for the implementation and maintenance of this Code of Practice as well as
application of the operational aspects of this philosophy on the transmission and sub
transmission system.
The Regional General Managers and Managers Planning shall be responsible for the
application of the operational aspects of this philosophy on the distribution system.
Modifications to protection systems or settings are to be undertaken by authorised
protection personnel only. Disciplinary action will be taken against any employees
found to be interfering with the protection systems without the appropriate
authority.
3
PROTECTION DESIGN
3.1
Design
All protection design shall comply with the following standards:
IEC 61000 Electromagnetic Compatibility
IEC 60255 Electrical Relays
Appropriate Australian Standards, including AS/NZS 3000 (SAA Wiring Rules)
The National Electricity Rules
CEOP8002 Protection Guidelines.
These standards shall be accepted as the minimum requirements.
Where practical, protection systems shall be designed to achieve the following objectives:
To detect all short circuit faults between phases and/or phase(s) and earth.
To detect abnormal operating conditions which may lead to failure of the network or
an unsafe condition arising
To allow the primary system being protected to operate within its rated voltage range
and carry its rated normal and emergency load currents, without the protection
system operating, failing or being damaged
To disconnect the faulted part of the network from the rest of the system in the
minimum practical time in order to:
o
minimise damage to the equipment and remainder of the network
o
prevent loss of stability of the network
o
minimise the probability of injury to personnel and livestock exposed to the
faulty equipment or to the faulted part of the network
o
minimise the probability or extent of damage to Essential Energy‟s property or to
other person‟s property as a result of the fault
o
minimise the extent and duration of interruption to supply as a result of the
fault.
To ensure safe step and touch potentials on the faulted network in conjunction with
the earthing system
To operate in a selective manner so that the minimum amount of the network is taken
out of service after a protection operation
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To be as reliable as possible, within cost-justifiable limits. To this end, duplicate or
back-up protection systems will be required in many situations
To ensure that allowance is made for future growth in the network and changes in
customer load requirements.
4
SUBSTATION BATTERIES
Substation batteries are identified as a critical single point of failure and as such should be
duplicated and supply the following protection equipment:
Transformer protection (which also protects the lower voltage plant)
Subtransmission feeders operating at 33kV and above.
The duplicate battery requirement need not be complied with where:
33kV circuits where remote backup protection is supplied by a separate battery
Equipment protected by fuses.
Existing substations which are augmented should meet this requirement. Where this is not
feasible and only a single trip battery is installed, remote backup protection shall be
provided.
4.1
Protection Sensitivity
All protection schemes shall have sufficient sensitivity to detect and correctly clear all
primary plant faults within their intended normal operating zones, under both normal and
minimum operating conditions. However, it is recognised that some faults cannot be
detected by the protection schemes, i.e., a broken conductor on the load side of the break.
Settings need to be chosen such that protection is as sensitive as possible without incurring
spurious trips or limiting operation of the network under credible system operating
conditions. In all cases minimum operating factors should be achieved.
4.2
Protection against Abnormal Operating Conditions
Protection specifically designed to detect overloads of transmission/subtransmission line
circuits or distribution circuits should generally not be fitted.
Oil insulated transformers, regulators and reactors larger than 1.5 MVA shall be protected
against loss of insulating oil.
Under abnormal primary plant conditions, any fault shall be detected and cleared by at least
one protection scheme somewhere in the system. Protection schemes affording remote
backup may be used for this purpose.
Under a single main protection scheme failure, any fault shall be detected and cleared by at
least one protection scheme somewhere in the system. Protection schemes affording
remote backup may be used for this purpose.
Where a protection scheme provides a backup function it shall have sufficient sensitivity to
detect and clear all primary plant faults within its intended backup operating zone under
both normal and minimum system conditions.
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4.3
CEOP8002
Protection Selectivity
Protection shall selectively trip the appropriate circuit breakers or fuses for the fault, with
minimum disturbance to the rest of the network. Protection shall also be set to be selective
for all faults, where all protection and circuit breakers (or other fault clearing devices) on
the system function as designed. It is also desirable that selectivity be maintained where a
single item of protection or a circuit breaker has failed to operate correctly.
Selectivity shall be ensured for the system configuration (lines, interconnecting
transformers and supply transformers) that exist for the majority of the time. Selectivity
shall also be ensured for credible operating conditions (corresponding to maximum and
minimum fault level conditions).
4.4
Fault Clearance Times
For a particular protection scheme, relay settings shall be such as to reduce fault-clearance
times to the minimum, without sacrificing selectivity of or with main protection.
Refer to section 5.2 for fault clearing times.
Consideration needs to be given to Earth Potential Rise and Voltage Contours in relation to
personnel safety and communications equipment and equipment ratings when selecting
clearance times.
4.5
Coordination of Protection Settings
Appropriate grading margins shall be applied to ensure protection coordination is achieved
in order to meet the requirements of selectivity. New protection settings need to be
coordinated with existing protection settings. Existing protection settings should be
reviewed and modified where necessary to allow for any system configuration changes
resulting from transmission, subtransmission, distribution or generation projects. Setting
records shall be kept in non-volatile media. Setting change control procedures shall be
applied.
4.6
Protection Flagging and Indication
All protective devices other than fuses shall be equipped with non-volatile operation
indicators (flags) or shall be connected to an event recorder. Such indicating, flagging and
event recording shall be sufficient to enable the determination after the fact of which
devices caused a particular trip.
4.7
Trip Supply Supervision Requirements
All protection scheme secondary circuits, where loss of supply would be a significant risk to
plant and personnel and would result in protection performance being substantially reduced
shall have trip supply supervision.
4.8
Trip Circuit Supervision
All new protection secondary circuits of 11kV and above that include a circuit breaker trip
coil shall have trip circuit supervision.
5
PROTECTION SCHEMES
Essential Energy shall apply the following minimum protection schemes as shown in Table 1.
Application detail is provided below.
Where duplicate protection schemes are installed these shall be of different hardware and
firmware configurations to ensure adequate redundancy.
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5.1
CEOP8002
Protection Scheme Selection
Table 1: Protective Devices
Plant
Transmission Feeders
Subtransmission feeders (22kV,
33kV and 66kV)
Transmission Plant
Subtransmission Plant > 8MVA
Subtransmission Plant =< 8MVA
Transmission Busbars
Subtransmission Busbars > 22kV
Protective Devices
Duplicate Main Protection schemes shall be installed. These
shall consist of Distance and/or Line Differential schemes.
Local CB fail shall be installed.
Duplicate trip batteries shall be installed.
Duplicate Main Protection scheme shall be installed. These
shall consist of Distance and/or Line Differential and/or 3phase Directional/overcurrent and Directional/earth fault
schemes.
Local CB fail should be fitted where practical, remote backup
shall be applied if no local backup is available.
Duplicate trip batteries shall be installed.
Reclosers will be considered where remote backup can be
achieved and directional functions are not required.
Duplicate Main Protection schemes shall be installed. These
shall consist of High Speed Biased Differential schemes, No.1
oil temp and winding temp, No.2 main tank buchholz, tap
changer buchholz and overpressure.
Local CB fail shall be installed.
Duplicate trip batteries shall be installed.
Duplicate Main Protection schemes shall be installed. These
shall consist of No.1 High Speed Biased Differential scheme, oil
temp and winding temp
No.2 High speed biased differential, main tank buchholz, tap
changer buchholz and overpressure.
Both relays should include backup OC and EF functions.
Local CB fail should be fitted where practical, remote backup
shall be applied if no local backup is available.
Duplicate trip batteries shall be installed.
Main Protection scheme consisting HV and MV Overcurrent and
Earth fault protection shall be installed (relays, reclosers or
fuses).
Local CB fail should be fitted where practical, remote backup
shall be applied if no local backup is available or duplicate
batteries are not installed.
Duplicate Main Protection schemes shall be installed. These
shall consist of High Impedance Differential schemes.
Local CB fail shall be installed between zones. Remote backup
shall be applied to cover busbar.
Duplicate trip batteries shall be installed.
Duplicate Protection scheme consisting High Impedance
Differential scheme should be installed.
Local CB fail should be installed between zones. Remote
backup shall be applied to cover busbar.
Where this busbar is normally radially connected, remote
backup protection can be provided for all connected circuits.
Where remote backup cannot be provided, a fault thrower is to
be installed.
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Plant
Distribution Busbars < 33kV
Distribution Feeders (Substation)
Distribution Feeders (Field)
5.2
Protective Devices
Main Protection scheme consisting High Impedance Differential
scheme should be installed.
Where the above cannot be achieved, protection shall be
provided by a combination of transformer Overcurrent and 2nd
high voltage Earth fault and Feeder initiated Blocking schemes.
Remote backup shall be applied to cover busbar.
Main Protection scheme consisting three phase HV
Overcurrent, Earth fault and Sensitive Earth fault protection
shall be installed (Relays or Reclosers)
On new or augmented installations duplicate main protection
schemes shall be installed. SEF need only be installed in one
of these schemes. CB fail protection shall be installed,
designed to trip the BBP or Transformer and Bus Section CB‟s.
Backup protection in the form of transformer lower voltage
overcurrent and earth fault (and also Negative Phase Sequence
for feeder backup if required) should be applied where BBP and
duplicate main protection does not apply.
Automatic reclosers, sectionalisers and Line fuses should be
installed in line with the following guidelines.
Remote backup protection should be applied by source side
device.
Fault Clearance Times
Fault clearance time should be as short as possible, and must whenever possible be short
enough to prevent avoidable damage to personnel or plant. The total clearing time - the
time for a permanent fault to be cleared from the system - will vary depending on fault
levels and number of automatic reclosers used on the system. See Attachment A for the
method of calculating total clearing time.
Where Critical Clearing Times are outside the National Electricity Rules requirements, an
application for exemption must be submitted supported by a stability study and report.
Table 2 shows the maximum clearing times for zero impedance faults under normal
conditions on the Essential Energy system.
Table 2: Fault Clearing Times
Protection operating times from fault inception to circuit breaker arc extinction shall not be
greater than:
Fault Clearance Times (ms)
Nominal
Source End
Voltage
Fault Location
As per NER Schedule 5,
More than 100kV 120 unless an existing
but less than 250 asset or new asset with
kV
AEMO exemption from
NER
66kV
200
Remote End
Fault Location
As per NER Schedule 5,
220 unless an existing
asset or new asset with
AEMO exemption from
NER
1000
33kV
1000
2000
4500
22kV
1000
_
_
11kV and below
1000
_
_
SEF
10,150
10,150
_
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Backup
As per NER Schedule 5,
430 unless an existing
asset or new asset with
AEMO exemption from
NER
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5.3
CEOP8002
Selection Requirements - General
Where possible without otherwise compromising the protection scheme (e.g., by
compromising selectivity), non-unit protection elements shall back up downstream
protection and downstream switching devices.
Protection schemes should be designed so that failure of one component should not
compromise the operation of other protection schemes.
Test facilities shall be provided for all relevant Protection schemes to enable the protection
trips to be isolated to all CB‟s individually and to enable secondary injection of volts and
current to be applied to any protection without affecting the complimentary protection or
taking the HV equipment out of service.
5.4
Transmission Plant
Protection installed to protect Essential Energy transmission plant and equipment shall be
designed to comply with the protection requirements of Table 1, and must be coordinated
with protection on transmission authority equipment. Where necessary to meet fault
clearance times referred to in Table 2, schemes should incorporate distance acceleration,
direct intertrip, or other high speed fault clearing techniques as required.
5.5
Subtransmission and Distribution Protection and Substation Plant
Protection installed to protect Essential Energy subtransmission plant and equipment shall
be designed to comply with the protection requirements of Table 1, and must be
coordinated with protection on source and load side equipment. Fault clearance times
referred to in Table 2 should be achieved and in all cases be as fast as practical to maximise
quality of supply.
While all Main Protection schemes remain in service there should be complete discrimination
for all faults. There may be a loss of discrimination under backup protection, but this should
be kept to a minimum.
Protection schemes applied should minimise voltage fluctuations experienced by other
customers. The use of instantaneous settings can assist with this aim.
Where Integrated relay schemes are installed these shall be fitted with self-monitoring
features and a fail-safe „Protection Faulty‟ alarm, and this alarm shall be monitored at the
appropriate remote control centre.
5.6
Main Protection
The Main Protection scheme (or each of 1 and 2 Protection) shall be „stand-alone‟ protection
designed for high reliability, security and discrimination. The role of this protection is to
clear any fault in the fastest possible time.
Main Protection should not, as far as is practical, share DC supplies, CT cores, VT cores, CB
trip coils or test facilities with the complimentary protection.
Duplicate Main protection schemes shall in general be from different manufacturers.
Fault location shall be provided in new installations for transmission and subtransmission
powerlines more than 20km in length or where the line crosses difficult terrain, either built
into a protection relay or as a separate relay. Fault location functionality should be added
to existing power lines where practical.
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5.7
CEOP8002
Backup Protection
Backup Protection shall be separate from the Main Protection, and shall be designed for high
reliability and security. The role of Backup Protection is to be available if the Main
Protection is unavailable (due to repair or maintenance etc.) or fails to operate. It shall
then clear any fault in the protected zone in as short a time as is necessary.
5.8
Distribution Transformers
This term includes SWER isolation transformers and reactors.
The majority of distribution transformers and SWER isolation transformers shall be
protected with fuses as specified in the Essential Energy Policy Distribution Transformer
Fusing CEOS5099.
Most distribution reactors are installed without specific protection, except for surge
suppression devices.
It is accepted practice to connect SWER reactors to existing rural substations (preferably
non-residential due to noise) using the same substation EDO fuse. This allows for easy
detection of faulty reactors or fuses blown by lightning. Which might otherwise remain
undetected as no customer call would be received for a reactor site.
On new SWER systems, backup can be achieved due to the larger conductor sizes, on older
established systems, backup can be very difficult and expensive to achieve. Under these
circumstances HV EDO fuses should be considered, as backup is not required for fuses.
5.9
Capacitor Banks
Capacitor bank protection shall consist of a combination of out of balance, overcurrent and
earth fault. Voltage protections should be considered where there is a high risk of damage
from over voltages. Other protection as recommended by the manufacturer shall be
installed. Close inhibit circuitry will normally be installed to prevent the energisation of
reverse charged capacitor banks.
None of these protections are alone sufficient to protect against all faults that may occur.
The concept of backup protection is not required for out of balance or over voltage schemes.
Trip isolation links and current and voltage test points shall be provided for each protection.
Schemes shall have redundancy such that if one capacitor section is out of service (for
maintenance or repair, or from an equipment failure) the protection will continue to
adequately clear any fault in the assigned protection zone.
5.9.1
Unbalance Protection
Where capacitor banks are installed as parallel banks with a common ungrounded neutral, a
sensitive overcurrent relay will be fitted to measure the current flowing between the banks
in the neutral conductor. This will detect bank unbalance caused by capacitor can fuse
operation in one of the banks.
5.9.2
Overcurrent Protection
Overcurrent relays covering phase and earth faults shall be fitted to detect faults external to
the capacitor cans. A single overcurrent and earth fault relay is adequate for a distribution
voltage capacitor bank provided a backup overcurrent and earth fault scheme can see faults
in the capacitor bank. A typical backup scheme would be a transformer overcurrent and
earth fault relay. For subtransmission capacitor banks duplicated protection is required.
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The overcurrent relays shall meet the same requirements as laid down in the Distribution
Feeder section of 7.1.1 (not including the SEF relay). An integrated relay including out of
balance protection is acceptable as one of the integrated overcurrent relays.
Where a capacitor bank is fused, consideration shall be given to including a protection
element set low enough to detect earth faults which remain back fed through the capacitors
and reactors of the unfaulted phases after the fuse has operated.
5.9.3
Reclose Inhibit
Unless the manufacturer indicates that it is unnecessary, a relay should be fitted to prevent
closure of the main capacitor bank CB until sufficient time has elapsed since the last trip, for
the capacitor cans to discharge to a safe voltage.
This function may be integrated in a relay providing other protective functions.
5.10
Circuit Breaker Fail
The purpose of a CB Fail scheme is to isolate a fault that has been detected by other
protection but not cleared. The fault may be not cleared because:
the CB failed to open in response to the trip signal; or
the CB operated but was not situated so as to clear the fault (a “blind spot” fault).
(This is uncommon or non-existent on the Essential Energy subtransmission and
distribution systems).
CB Fail shall consist of a timer and an overcurrent check relay. The timer will be initiated by
the primary protection trip command or scheme multitrip relay. The time setting for
<100kV should be 300ms and 100kV> to comply with NER schedule 5, the timer shall cause
a trip to all other circuit breakers necessary to clear the fault if and only if the overcurrent
check relay detects fault current still flowing.
CB Fail may be integrated with Backup Protection relays, as it is called upon to operate on a
CB failure, and the combination of a CB failure and Backup Protection failure is regarded as
sufficiently unlikely to be discounted.
6
SETTING PHILOSOPHY – ZONE SUBSTATION SCHEMES
The following section describes the requirements for the setting of the following protection
schemes within Zone Substations.
6.1
Distance Schemes
Where distance schemes are employed, the following setting criteria shall be applied.
6.1.1
Number of Zones
A minimum of three (3) forward (towards feeder) zones shall be used. In unusual
circumstances, a fourth forward reaching zone may be used if it can provide faster
operating times whilst still providing suitable grading with downstream protective devices.
Dedicated reverse reaching zones are typically not to be used unless unusual circumstances
require such an element to be used (However for some relay types predominantly forward
reaching zones which have a small reverse reach to ensure coverage for faults of very low
impedance which result in very low voltage, are acceptable).
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In cases where a dedicated reverse reaching zone is set up, the following shall apply:
6.1.2
a
A justification for the use of such an element is recorded in the file notes for that
circuit breaker, and no other more conventional alternatives exist
b
A note is made in the caution notes of the PSA regarding the use of the reverse
element
c
The reverse element is graded with all downstream protection
d
The reverse element is only to be used as backup protection
e
The IED is programmed with a display which clearly indicates the fact that the reverse
element operated.
Quadrilateral Ground Protection
Where available, quadrilateral ground protection zones are to be used, as they provide
additional resistive coverage.
Such resistive reaches should be set as large as possible, however care is to be exercised to
ensure that the resistive element is not set to an excessive level, without due regard to any
potential overreach. In general: Quad resistive reach shall not exceed:
6.1.3
a
Manufacturer‟s recommendation, or
b
Shall be designed to cater for any possible overreach due to CT/VT errors and system
non-homogeneity.
Zone 1 Protection
Zone 1 is used to provide instantaneous protection to the protected feeder. As much of the
feeder as possible should be covered by Zone 1, whilst taking into account the following:
1
In general, Zone 1 should not see into any part of the system which is covered by
downstream protection, in order to ensure grading. This will limit the maximum reach
of Zone 1
2
An allowance must be made for the possibility that the relay can over-reach due to
relay CT/VT errors; hence the relay must be set short of the impedance to the remote
relays as determined by the previous point. A setting value of 80% of the line
impedance to the remote relay is typical; however this may need to be shortened.
3
0 should be calculated on the impedance of the
The residual compensation factor
section of line determined in the above first point, as Zone 1 typically requires the
most accuracy to ensure that it does not reach into the area covered by remote
downstream relays.
K
Timing – Zone 1 should be set instantaneous in all normal circumstances.
6.1.4
Zone 2 Protection
Zone 2 is used to provide fast protection of the remainder of the feeder that cannot be
covered by Zone 1 as it overlaps with the downstream protection, it needs to have a time
delay to ensure grading.
Zone 2 reach shall be set as follows:
1
To cover the entire length of the protected feeder. This will require the calculation of
the maximum impedance between the relay point and any part of the line to be
protected
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2
An allowance is made for relay under-reach. Setting values chosen should not be less
than 120% of the maximum line impedance determined from the previous point
3
As arcing faults /infeed are highly likely, an allowance for arc resistance should be
made. Refer to section 6.1.6 for details of determination of arc resistance.
This allowance will often require the increase of Zone 2 impedance setting past the value
required by the previous point, although this may not be required where Quad elements are
used. Where studies indicate that zone 2 cannot be set large enough to cover all arcing
faults, the zone 2 reach shall be set as large as practical and zone 3 should be used to cover
such faults.
Zone 2 timing shall be set as such:
1
Zone 2 must grade with any downstream protection within its potential reach.
Note that under the following circumstances, grading need not be provided:
2
6.1.5
a
Zone 2 does not need to grade with transformer high voltage overcurrent and
earth fault (HVOC and EF) provided that the transformer is also covered by
instantaneous differential protection AND Zone 2 does not extend into the
transformer low voltage bus
b
Zone 2 does not need to grade with downstream feeder HVOC and EF, provided
that the same downstream feeder is provided with a distance relay or pilot wire
relay, AND Zone 2 does not extend past the instantaneous reaches of these
downstream high speed relays.
Timing for Zone 2 should not exceed the criteria as specified in Table 2 Fault clearing
times in section 5.2.
Zone 3 Protection
Zone 3 is typically used to provide remote backup of downstream equipment. It is
important to note that Zone3 need only provide backup for a single contingency event, that
is the failure of one protective device only per event.
Zone 3 reach shall be set as follows:
1
Primary feeder arcing fault coverage.
Where it is not practical to cover for arcing faults within zone 2, zone 3 should be set to
cover such faults in the primary protection zone.
2
Downstream Feeder Backup.
Zone 3 shall protect any feeder supplied by a downstream substation. Note that the effect
of infeed from other feeders should also be taken into account. See Note below. The
required reach of the relay should be calculated for system normal conditions only, provided
zone 3 is used for backup protection.
3
Downstream Substation Transformer protection.
Zone 3 shall protect any bus fed by transformers of a downstream substation. The effect of
infeed should be catered for, as should three phase, two phase and phase to earth faults.
The required reach of the relay to the bus shall be calculated using system normal
conditions only, provided zone 3 is used for backup protection.
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The setting selected for Zone 3 should ensure stability for inrush during memory
operation. The reach selected should also ensure stability during high load periods.
Note: This note requirement is not essential for downstream substations equipped with
duplicate batteries, feeder protections and trip coils, although it is still good practice to do
so. In the event that this requirement is unable to be met, alternative solutions to backup
should be sought, these include:
a
Installation of duplicate protection in downstream substations, especially if it is
part of a critical ring
b
Further investigation to determine if the fault will be cleared by sequential
operation of protective devices, provided safe clearing times for the faulted
feeder can be observed
c
Determine if second protection (where provided eg DOC) will see the fault
d
Use of DTOC, DTEF or NPS elements to detect the fault.
Zone 3 timing shall be set as such:
1
Zone 3 must grade with any downstream protection within its potential reach.
In general, Zone 3 need not be graded with Zone 3 protection of other downstream distance
relays, unless it is determined that if it is possible that such a malgrade is likely to cause an
unnecessary loss of customers for a single contingency failure.
2
6.1.6
Zone 3 should not be set to greater than four (4) seconds (preferably three (3)
seconds). In the instance where this is not possible, the reach should be reviewed.
Mutual Coupling
Reach of phase – earth elements shall also consider effects of mutual coupling which may
cause the relay to over or underreach.
6.1.7
Arcing Resistance / Infeed
It is recognized that arc resistance and infeed can significantly affect the apparent
impedance seen by a distance relay.
In order to allow for this effect, the following considerations should be taken:
1
Arcing Resistance.
In order to calculate arc resistance for phase faults, use
a
Method recommended by relay manufacturer
OR
b
R ARC
28710 L
I 1.4
where L = Average phase to phase or phase to earth distance in metres
where I = Fault level at line end (with zero resistance).
2
Apparent impedance due to phase to phase faults.
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Use data from fault study program using arc resistance as per 1 above to determine
apparent impedance.
3
Apparent impedance due to phase to earth faults.
Add arc resistance as per 1 above to tower/pole footing resistance to achieve overall fault
resistance. Use calculated fault resistance to determine apparent impedance.
6.1.8
Loss of Potential
Loss of VT supply to a distance relay may either render it inoperable or cause it to trip.
Where the relay permits, an emergency overcurrent and earth fault element should be used
which is activated by the loss of VT supply.
6.1.9
Broken Conductor Detection
For radial subtransmission feeders with delta connected transformers, consideration shall be
given to implementing broken conductor elements if available in the installed protection
relays.
6.2
Directional Overcurrent and Earth Fault
Directional Overcurrent (DOC) and Earth Fault (DEF) protections are sometimes used on
meshed subtransmission feeders as the second of the two main protection schemes and on
the lower voltage side of parallel transformers. They can generally be set more sensitive
and with a faster operating time than normal OC protection as grading is not required with
all other OC devices.
The Voltage Transformers (VT) used for these schemes must be of the 5 limb type or 3
single phase units to obtain the correct residual voltage from an Open Delta connection.
Modern relays simulate the Open Delta residual voltage within the relay.
The same grading principle applies as detailed in section 7.1.1 for other devices in the
current direction. The DOC devices should be set above load even if the device is setup to
detect faults in the direction opposite load.
The most common connection used in Essential Energy older systems for DOC is the 90 deg
connection with a 45 deg relay angle (quadrature connection) – The „A‟ phase relay is
supplied with Ia and Vbc which results in the current applied to the relay leading the volts
applied to the relay by 45 deg. This connection gives a correct directional tripping zone
over the range of currents 45 deg – 135 deg lagging. Other connections are available but
the above suits the majority of Essential Energy situations.
DEF relays are of a similar construction to the DOC older relays and are fully integrated in
the newer IED relays. These are polarised by the residual voltage, in this application the
applied current lags the applied voltage, so the relay angle chosen should be -45 deg for
distribution systems and -60 deg for subtransmission systems.
The newer IED relays have varying methods of calculating DOC and DEF operating
parameters and should be investigated and set in accordance with the manufacturers‟
recommendation.
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6.3
CEOP8002
Line Differential Protection and Communications Assisted Distance
Schemes
Where subtransmission feeders are short and either a communications channel is available
such as an optical fibre installed for other reasons, or reasonable protection clearing times
and grading cannot be achieved using distance protection, a line differential scheme should
be installed. If two communications paths are available then use of the second
communications path should be made to provide redundancy as the communications path is
a likely source of failure. The scheme should normally be a number 1 protection scheme
except where the protected feeder is connected to an asset owned by others and the relay
make and model cannot be of Essential Energy‟s selection, in which case it is acceptable to
install it as a number two scheme. Distance backup of a line differential scheme is
acceptable, and it is not necessary for the distance backup scheme to achieve grading with
other elements in the network.
In some cases, especially in order to meet NER clearance times, a duplicate line differential
or line differential scheme and communications assisted distance scheme may be required.
In this case independent communications paths are required. Two OPGW‟s on a single
structure are not considered independent communications paths.
6.4
Busbar Protection
Busbar protection is used on Substation busbars of 11kV and above. High impedance busbar
protection is the preferred scheme. Other schemes may be considered where special
circumstances require.
6.4.1
Location of Busbar CT’s
Busbar protection CT‟s must be located on the circuit side of each circuit breaker, otherwise
a blindspot could occur which is neither cleared by Busbar protection or other unit
protection schemes, and may have to be cleared by remote protection.
6.4.2
High Impedance Busbar Protection
High impedance Busbar protection is the only Busbar protection scheme that is currently
approved for use within Essential Energy.
The following requirements apply with the use of Busbar protection:
1
2
CT Requirements.
a
Class PX CT‟s are to be used for all new Busbar protection schemes as the knee
point voltage and secondary resistance are well known.
b
The kneepoint voltage of the CT shall be a minimum of two (2) times the
proposed relay setting voltage
c
The CT‟s used in the scheme must all be set on the same ratio
d
Interposing CT‟s are not to be used with high impedance Busbar protection.
Relay Voltage Limitation.
To prevent damage to equipment or secondary wiring the voltage across the element of a
high impedance Busbar protection relay shall be limited by a suitably rated voltage limiting
device such as a „Metrosil‟.
3
Relay Voltage Stabilisation.
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The relay setting voltage shall not be set lower than the following:
VRELAY
I FAULT
RCT
RLEADS
Where:
VRELAY is the setting voltage of the relay
I FAULT is the secondary current that would flow for a worst case primary fault
RCT is the highest winding resistance of any CT used in the scheme
RLEADS is the resistance of leads from the CT to the relay
Note: VRELAY must be less than half (1/2) the kneepoint voltage of the worst CT used in
the scheme.
6.5
Transformer Protection
Where used, transformer protection should be set in accordance with the following
guidelines:
6.5.1
Transformer Differential Protection
1
Biased Differential element setting.
The biased differential element must be set to be stable under the following
conditions:
a
Maximum through fault conditions, regardless of tap setting. This requires that
the bias slope be set to compensate for CT errors and a variable tapchanger
setting. Bias slopes should be set as per relay manufacturer‟s recommendations
b
Restrained for inrush.
Where configurable, the following harmonic restraint or harmonic blocking elements should
be set:
Second harmonic
Fourth harmonic
Fifth harmonic
DC.
Care needs to be exercised when setting or applying a biased differential relay which
protects two or more transformers, as prolonged inrush imbalances can occur when a
second transformer is energised.
In such cases, additional precautions need to be taken, such as custom blocking logic.
c
2
Must be sensitive enough to positively operate for faults inside the protected
zone.
Unrestrained Differential element setting.
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These elements are provided to very quickly detect high differential currents which clearly
indicate the presence of an internal fault. The guidelines for the setting of these elements
are as follows:
3
a
Elements are often not provided with any form of harmonic restraint or blocking
and hence can operate for transformer inrush. Hence care must be taken to
ensure the setting is not too low to operate under energisation
b
If possible, the unrestrained element should be set to cover High Voltage
terminal faults, although this may not always be achievable, depending upon the
fault level.
CT Selection.
Biased differential relays
a
Ratio chosen – CT ratio should be chosen so that rated secondary current does
not flow at primary currents LESS than 140% of the maximum rated current for
the relevant transformer winding.
It is recognised that this requirement may not be economically achievable for
existing schemes, hence a lower ratio is acceptable, provided the CT and relay
can continuously withstand such current OR it can be shown that there is no
reasonable possibility of the transformer being subject to greater than 150% of
its secondary rating.
b
CT Kneepoint voltage.
In general the minimum CT kneepoint voltage for use in transformer differential circuits
shall be determined by:
Vk
I f sec
1
X
R
RCT
RBURDEN
Where - Vk is the knee point voltage of the CT to be used.
Vk
Vk
I f sec
Vk
I
f sec
1
X
R
1
Vk
RCT
RBURDEN
X
R CT
R
I f sec
I f sec
X
R
1
X
R
1 the maximum
RCT RCT
BURDEN
is
secondary current flowing due to a through fault
is the secondary resistance of the CT
is the combined resistance of the CT‟s burden (leads, relays,
R BURDEN
interposing CT‟s etc)
RCT
RBURDEN
is the Inductive Reactance/Resistance ratio of the fault.
This knee point voltage requirement should be carefully adhered to for the following
reasons:
Saturation may cause spurious tripping due to through faults
CT saturation under internal fault conditions may produce current harmonics
which may cause the relay‟s harmonic blocking system to delay the relay‟s
operating time.
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6.5.2
CEOP8002
Transformer Restricted Earth Fault Protection
Restricted Earth Fault (REF) is a form of unit protection employed on star transformer or
generator windings. Its main advantage over differential protection is that it is highly
sensitive to earth faults in the star winding which occur in approximately the half of the
winding which is closest to the star point. Such faults do not usually cause a large amount
of phase current to flow, but do result in a high neutral current flow.
There are two types of REF protection relays in common use within Essential Energy:
1
High Impedance REF:
This protection works on the same principle as the high impedance BBP relay. The
requirements for the setting and selection of these schemes are as follows:
2
a
CT requirements - as per section 6.4.2 (1)
b
Relay Voltage Limitation – as per section 6.4.2 (2)
c
Relay Voltage Stabilisation – as per section 6.4.2 (3).
Low Impedance REF (typically numerical or electronic relays):
a
Stability Setting.
The low impedance REF must be set to be stable under maximum through fault
conditions (especially for earth faults). The likelihood of CT saturation should be taken
into account.
Ideally, the relay should be restrained (or blocked) if the neutral CT current does not
exceed a threshold value as an absence of neutral CT current indicates that there is no
fault within the relay‟s zone. A three phase out of zone fault can produce significant
“false” residual current.
b
CT selection - Phase CT‟s.
As the phase CT‟s shall usually be the same as those used in the biased differential
relay, they shall be selected in accordance with 6.4.2 (1) (a).
c
CT selection - Neutral CT‟s.
For relays which do not have internal CT tap compensation, the REF CT‟s must be
selected to be the same ratio and class as the phase CT‟s.
For relays which do have internal CT tap compensation, a ratio lower than the phase
CT‟s may be selected provided all of the following is applied:
The knee point voltage produced on that ratio is not less than the value required by
6.4.2 (1) (b)
The relay chosen can compensate for the ratio mismatch proposed
It is preferred that the ratio of the neutral CT is not less than half of the ratio of the
phase CT‟s.
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6.5.3
CEOP8002
Transformer Thermal Protection
Transformer thermal protection is provided to ensure that the winding insulation is not
subjected to excessive temperature rises for long durations. Insulation temperature rises
above the design temperature can reduce the lifespan of the insulation.
There are cases however, where it is necessary to subject the transformer windings to
temperatures marginally in excess of the design temperature for short durations. Whilst
this does have a minor detrimental effect on the insulation life of the transformer, it allows
supply to customers to be maintained.
There are two variations in design criteria applied, pre 1998 and post 1998. For simplicity,
these have been combined to provide a standard for Essential Energy.
The Winding Temperature indicator is a summation of the oil temperature and the difference
between the average winding temperature and the average oil temperature multiplied by
1.1 to account for the „hottest spot‟, the latter provided through a CT and heater/shunt
combination to simulate the winding temperature at varying loads.
Where fitted, thermal protection should be set as follows:
1
To the manufacturer‟s recommended settings (provided they are relevant to the
transformer‟s present configuration)
OR
2
To the following settings, if the manufacturer‟s settings cannot be obtained or are
considered no longer applicable to the transformer in its present configuration (eg a
transformer may have been upgraded from ONAN to ONAF).
Hot Oil Alarm setting = 90degC
Hot Oil Trip setting = 105degC
Hot Winding Alarm setting = 110degC
Hot Winding Trip setting = 125degC
Fan and Pump Control - based on winding temp sensor reading
Pumps On = 60degC
Pumps Off = 50degC (where sensor differential permits).
Fans On = 65degC
Fans Off = 55degC (where sensor differential permits).
Fan and Pump Control - based on Oil temp sensor reading
Pumps On = 55degC
Pumps Off = 45degC (where sensor differential permits).
Fans On = 60degC
Fans Off = 50degC (where sensor differential permits).
Winding Temperature Indicator Setting
The Temperature gradient (G)
Where
=T-k
T = average winding temperature rise for steady conditions
k = constant ratio of average temperature rise to top oil temperature rise
= 0.8 for natural oil cooled transformers prior 1959
= 0.97 for forced oil cooled transformers prior 1959.
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OR
Where test figures are available
k = 1 – temperature difference between inlet and outlet / 2 X temperature rise of the top
oil.
= top oil temperature rise for steady conditions at test load
Determination of Injection temperature rise
6.5.4
6.5.5
T‟ = 1.1 X G
T‟ = 1.1 (T-k ).
Determination of Injection current
IT‟ = VAmax (OFAF) X CT ratio / 3 X V.
Determination of Heater/Shunt current
IH = IT‟ X RS/RH + RS
Where IH = Heater current
RH = Heater resistance + leads
RS = Shunt resistance.
Transformer Mechanical Protection
1
Main Tank Buchholz shall be fitted to all transformers above 5MVA. These devices will
have an alarm for gas collection and a trip for oil surge. A low oil trip shall be set up
for transformers above 15MVA in zone substations with a full N-1 capacity.
Consideration to implementation of an auto changeover scheme is also to be given in
conjunction with the implementation of low oil trip where one of the transformers is
normally on standby
2
Tap Changer Buchholz or oil surge device shall be fitted to all transformers above
5MVA fitted with on load tap changers. These devices shall be set to trip
3
Overpressure devices should be fitted to larger transformers. Where fitted these
devices should be set to trip.
Transformer High Voltage Overcurrent and Earth Fault Protection
High Voltage Overcurrent and Earth fault protection shall be set as follows:
1
CT Ratio chosen – CT ratio should be chosen so that rated secondary current does
not flow at primary current LESS than 140% of the maximum rated current of the
transformer
2
Overcurrent pickup – The primary overcurrent pickup should be set to 140%> of
the maximum rated current of the transformer
3
Overcurrent grading – The relay timing shall be designed to grade:
4
a
Above all downstream devices for three phase, phase to phase and phase to
earth faults
b
Below upstream devices. Note that this requirement does not apply for upstream
distance relay Zone 2 reach when in accordance with Section 6.1.4.
Instantaneous Overcurrent grading – High Voltage Instantaneous Overcurrent
elements should be set in accordance with the following:
a
Low Voltage faults will not operate Instantaneous Overcurrent under maximum
fault conditions
b
Instantaneous Overcurrent pickup level should be greater than eight (8) times
the ONAN rating of the transformer, with the preferred value to be ten (10)
times.
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5
6
7
CEOP8002
Earth fault pickup – The Earth fault pickup shall be set as low as practical whilst
ensuring the following is observed:
a
Current grading with downstream devices, for transformer‟s that are able to
allow zero – sequence currents to flow through them
b
In any case, not less than 10 Amps.
Earth fault grading – The relay timing shall be designed to grade
a
Above all downstream devices, if the transformer is able to allow zero –
sequence currents to flow through them
b
Below upstream devices.
Instantaneous Earth fault – Instantaneous EF should be set to the same criteria as
the IOC above. This element will provide some benefits for phase-phase-earth faults.
6.6
Distribution Busbar Protection
6.6.1
Transformer Low Voltage Overcurrent and Earth Fault Protection
Transformer Low Voltage Overcurrent and Earth Fault (LV OC and EF) shall be set as
follows:
6.6.2
1
CT ratio chosen – (140% as per HV)
2
OC grading. Relay shall grade:
a
Above all feeder downstream devices
b
Pickup should be 140%> than the maximum rated current of the transformer
unless required to be lower for distribution feeder backup and the
anticipated load is lower than the maximum rated current.
c
Below transformer OC protection for three phase and two phase faults.
3
Instantaneous Overcurrent (IOC) - LV IOC elements are usually not used as they
cannot grade with feeder OC protection. These elements can be used as part of a
blocking scheme (refer Section 6.6.4 (1) (b)
4
Earth Fault (EF) pickup – EF pickup to be set to grade above downstream relays.
Pickup should be kept to the minimum value needed to maintain current grading
5
Instantaneous Earth Fault (IEF) – as per IOC Section 6.6.4 (1) (c).
Transformer Low Voltage Neutral Earth Fault Protection
Where used, Transformer Neutral Earth Fault (NEF) shall be set as follows:
1
CT ratio chosen – Where a NEF relay is fed from a dedicated CT, the NEF CT ratio
chosen shall be at least 1/20th of the maximum respective fault current that can flow
through the CT
2
NEF grading – as per EF pickup Section 6.6.1 Part (4) above
3
IEF – instantaneous NEF elements should not be used.
Where transformers are only fitted with high voltage protection, NEF protection should be
installed tripping the HV circuit breaker.
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6.6.3
CEOP8002
Lower Voltage Busbar Protection Scheme
These should be used as the preferred scheme for the lower voltage busbars. Refer
requirements for section 6.4.
6.6.4
Blocking Schemes for Distribution Busbar Speed Enhancement
Blocking schemes are occasionally used in lieu of busbar protection to improve the clearing
times of distribution busbar faults. They consist of fast definite time overcurrent and earth
fault elements used in the transformer circuit breakers and the bus ties.
These fast elements will operate for high fault currents, unless a downstream relay also
sees the fault and sends a blocking signal to the relay with the fast definite time element, to
prevent it from operating.
The components of a blocking scheme shall be set as follows:
1
Transformer Low Voltage Overcurrent and earth Fault
a
The Overcurrent and Earth Fault element shall be set normally as per section
6.5.5
b
An instantaneous Overcurrent element shall be set to operate at 60% of the
phase to phase fault current that would be seen by that device under system
normal conditions. The delay required for the instantaneous Overcurrent shall
be as per (d) below
c
An instantaneous Earth fault element shall be set to operate at 40% of the phase
to earth fault current that would be seen by that device under system normal
conditions.
Note: For earth fault limited systems this requirement is not valid and the following shall
apply:
Setting must be less than normal earth fault current through device.
Setting must be at least twice the value of the highest downstream earth fault element
pickup which blocks it.
d
Timing – The instantaneous Overcurrent and instantaneous Earth fault elements
shall have the following delay applied:
Downstream Electronic relays – 200ms
Downstream Nulec Reclosers – 250ms.
2
Bus Circuit Breaker
a
The bus circuit breaker shall have Inverse Definite Minimum Time, Overcurrent
and Earth fault set to grade between the transformer circuit breaker and the
feeders
b
An instantaneous Overcurrent and Instantaneous Earth fault element set as per
(1) (b) and (1) (c) above
c
Timing – The Instantaneous Overcurrent and Instantaneous Earth fault shall
have the following delay applied:
Downstream Electronic relays – 80ms
Downstream Nulec Reclosers – 200m.
d
Two sets of Directional Overcurrent and Earth fault elements shall be used to
produce a blocking signal for the circuit breakers in the reverse direction.
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The other of these elements shall face the reverse direction and be used to produce a
blocking signal for the circuit breakers in the opposite direction.
The pickups of these directional elements shall be as follows:
Overcurrent – Must be set greater than load but less than the pickup value
determined in (b) above. An initial value of 120% of Overcurrent pickup
(as per (a) above) is suggested
Earth fault - Must be set greater than the highest downstream earth fault
element but less than the pickup value determined in (b) above. An initial
value of twice the highest downstream Earth fault element is
recommended.
There shall be no delay on these blocking elements.
3
Feeder Circuit Breakers involved in protection blocking
a
Feeder circuit breakers shall be set as per Section 7.1.1 for distribution feeders,
7.2.3 for Capacitor circuit breakers and Section 7.3.1 for Frequency Injection
plant
b
In all cases the following shall apply:
Overcurrent or Earth fault pickup instantaneously closes a protection
blocking send signal.
6.7
Subtransmission Undervoltage and Underfrequency Protection
6.7.1
Undervoltage Protection
Where required, undervoltage settings shall be determined by the Transmission System
Network Service provider as per S5.1.10.2 of the National Electricity Rules.
6.7.2
Underfrequency Protection
Where required, underfrequency settings shall be determined by AEMO, as per S5.1.10.2 of
the National Electricity Rules.
6.8
Sub Transmission Automatic reclose
6.8.1
Automatic Reclose Justification
Because a large proportion of faults are of a transitory nature, it is normally an advantage
to attempt to reconnect a sub-system that has been isolated by protection operation after a
fault, if this is likely to restore supply to the sub-system without undue risk to personnel,
livestock, or plant.
6.8.2
Subtransmission Feeders
Automatic reclose shall be used on all Essential Energy Subtransmission feeders and be
initiated by No1 and No2 feeder protections, with the exception of the following case:
Zone 3 of distance protection usually acts as a backup for other downstream
protection. If it is possible to treat zone 3 trips separately, zone 3 trips should not
initiate an automatic reclose, unless used for primary protection.
Auto reclose shall be blocked in a switch on to fault condition.
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Auto reclose should not be used on subtransmission feeders which are entirely
underground or where the overhead section is very short and there is little chance of a
transient fault in the overhead section.
6.8.3
Subtransmission Transformers
Automatic reclose should not be used on transformers in Essential Energy‟s Transmission,
Subtransmission and Zone Substations.
6.8.4
Subtransmission Busbars
Automatic reclose should not be used in conjunction with busbar protection in Essential
Energy‟s Transmission, Subtransmission and Zone Substations. Exceptions will be granted
in substations where previous experience indicates that environmental conditions are such
that faults of a transient nature are a common cause of busbar faults. In such cases,
automatic reclose may be used to successfully restore supply without undue risk to
personnel, livestock, or plant.
6.8.5
Automatic Reclose Timing
Reclose dead time settings shall include allowance for:
likely risk to personnel on or arriving at the scene
switch operating mechanism reset and stabilise time, including contact cooling times
after passing fault current
relay reset time
likely effects on customer equipment of a restoration of supply after a short outage
effects on equipment, including risk of damage from the mechanical and electrical
effects of repeated fault current and trapped charges.
Subtransmission Feeders
A reclose dead time of 5 - 10 seconds should be used on Essential Energy‟s Subtransmission
feeder network. The longer time has been proven on Transmission and Subtransmission
networks to provide the best chance of restoring a transient faulted feeder to service.
Subtransmission Busbars
When allowed, a reclose dead time of 5 seconds should be used on Essential Energy‟s
Subtransmission busbar network.
6.8.6
Automatic Reclose Attempts
The majority of transient faults will be cleared by a single tripping operation.
Automatic reclose shall be disabled prior to:
live line work
any manual close of a CB, including re-energising plant following maintenance and
energising plant while sectionalising to locate a fault.
Automatic reclose shall not be used for customer owned lines or for lines dedicated to one
customer unless authorised by the customer.
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One reclose attempt should be used on Essential Energy’s Subtransmission feeder
network.
Refer to Attachment A for Total Fault Clearing Time calculations, methods and Terms.
7
SETTING PHILOSOPHY – DISTRIBUTION SCHEMES
7.1
Distribution Feeder Protection within Zone Substations
Distribution feeder protection within Zone Substations should be set in accordance with the
following guidelines:
7.1.1
Feeder Overcurrent and Earth Fault Protection
1
CT Ratio chosen – CT ratio should be chosen so that rated secondary current does
not flow at primary current LESS than 120% of the maximum continuous load current
of the feeder.
New installations should have duplicate three phase overcurrent and earth fault installed.
This should also be considered on existing substantially UG cable systems. The two systems
shall be of different manufacturers and types, set substantially the same, be supplied from
separate batteries and operated into separate trip coils. Where practical a second CT core
should be used, but a common CT core is acceptable.
All associated ancillary functions eg SCADA and auto-reclose shall reside in the primary
protection.
Where full primary and backup lower voltage protection is installed, there will be no
requirement to provide backup protection from the transformer systems.
2
Overcurrent pickup – The primary overcurrent pickup should be set as follows:
a
To be greater than the five year forecast maximum load X 120% and
b
To be greater than maximum predicted cold load. This predicted value can be
obtained in one or more of the following ways:
By past experience of cold load problems on the feeder.
By prediction based on the maximum recorded feeder load experienced in a one year
period. In this case, a margin of 10%* should be added to ensure security.
By prediction based on the maximum expected feeder load from a load flow study. In
this case, a margin of 10%* should be added to ensure security.
*Note: this margin may be increased for feeders where the backup requirements are met
at higher settings.
As an alternative to a permanent overcurrent setting above the cold load, the “Cold Load”
multiplier function available within some recloser controllers may be used to ensure the
recloser can be closed onto cold load.
c
The overcurrent pickup should be set so as to ensure the following Operating
Factors are observed:
Primary Protection Operating Factor - The overcurrent setting should provide a primary
Operating Factor of 2.0 for phase-phase faults.
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*Note: In the event that the above operating factor cannot be achieved without excessive
and/or uneconomic system redesign, then both of the following shall apply:
An Operating Factor of 1.5 should be achieved using the normal calculations.
AND
The effect of minimum feeder load current should be used in the software calculation of the
minimum current seen by the relay for phase-phase faults. The ratio of this calculated
minimum current (including load) to primary relay current pickup should exceed 1.75.
Backup Protection Operating Factor - The overcurrent setting should provide a backup
Operating Factor of 1.5 for phase-phase faults.
*Note: In the event that the above operating factor cannot be achieved without excessive
and/or uneconomic system redesign, then both of the following shall apply:
An Operating Factor of 1.35 should be achieved using the normal calculations.
AND
The effect of minimum feeder load current should be used in the software calculation of the
minimum current seen by the relay for phase-phase faults. The ratio of this calculated
minimum current (including load) to primary relay current pickup should exceed 1.5.
The feeder overcurrent relay pickup should be set higher than the downstream device(s)
overcurrent pickup. This requirement need not apply in instances where it can be justified
that time grading is still likely to exist between these devices for all practical fault
situations.
*Note: Typically the ratio of maximum three phase fault current seen by the device to
overcurrent primary pickup should not be greater than 20X.
Overcurrent timing – The relay overcurrent timing shall be set as such:
Above all downstream devices for three phase, phase to phase and earth faults up to the
maximum fault levels present at the downstream device location.
Below upstream devices, up to the maximum fault level that the feeder and upstream
device shall simultaneously see for a feeder fault.
To protect any conductor within its Primary and Backup zone against thermal damage for
fault levels that may be experienced by it.
The following time grading margin between the feeder and upstream devices should be
used:
If the upstream relay is electronic - 300ms minimum, 400ms preferred
If the upstream relay is an induction disk type - 400ms minimum.
The following time grading margin between the feeder and downstream devices should be
used:
If the feeder relay is electronic - 300ms minimum, 400ms preferred
If the feeder relay is an induction disk type - 400ms minimum.
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Overcurrent IDMT curves - Where possible, IEC 60255 “SI” or “VI” curves are preferred.
Other curves may be used where the downstream protection does not suit the use of the
preferred curves.
High Set Overcurrent Elements - Where available, high set overcurrent elements may be
used, provided that the element is not capable of reaching to any downstream recloser
under maximum fault conditions or operating due to feeder energisation inrush. In order to
prevent malgrading with distribution transformer fuses, a 300ms definite time delay setting
is preferred over an instantaneous setting.
Earth Fault pickup – The primary Earth Fault pickup should be set as follows:
significantly less than the feeder Overcurrent pickup
As low as possible
To grade with downstream protection, but not with distribution transformer fuses, and
not with fuses in general if it can be justified that time grading is still likely to exist
between these devices for all practical fault situations
Typically a maximum of 100 A at the zone substation.
The Earth Fault pickup should be set so as to ensure the following Operating Factors are
observed:
Primary Protection Operating Factor - The Primary Earth Fault Operating Factors should
apply:
For feeders without SEF protection - 1.75 (based on 20 ohm fault resistance)
For feeders with SEF protection - 1.75 (based on 0 Ohm fault resistance).
Backup Protection Operating Factor - The Backup Earth Fault Operating Factors should
apply:
For feeders without SEF protection - 1.5 (based on 20 ohm resistance as per Minimum
Fault Level definition in section 2)
For feeders with SEF protection - No specific Operating Factor is required, provided an
SEF relay operating factor of 2.0 is maintained.
It is noted that in accordance with Essential Energy‟s proposed implementation of EG(0)
Power System Earthing Guide, it is not required to have backup protection for faults to earth
which include a „remote‟ conductive structure in the earth path. The term „remote‟ here
means „remote‟ as defined in EG(0).
Earth Fault Timing – The Earth Fault relay timing should be set as follows:
Above all downstream devices for earth faults up to the maximum fault levels present
at the downstream device location. Note that time grading should be achieved over
distribution transformer fuses; however time grading does not need to be achieved
over larger fuses
Below upstream devices, up to the maximum fault level that the feeder and upstream
device shall simultaneously see for a feeder earth fault
To protect any conductor within its Primary and Backup zone (where required) against
thermal damage for fault levels that may be experienced by the conductor.
The following time grading margin between the feeder and upstream devices should be
used:
If the upstream relay is electronic - 300ms minimum, 400ms preferred
If the upstream relay is an induction disk type - 400ms minimum.
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The following time grading margin between the feeder and downstream devices should be
used:
If the feeder relay is electronic - 300ms minimum, 400ms preferred
If the feeder relay is an induction disk type - 400ms minimum.
Earth Fault IDMT curves - Where possible, IEC 60255 “SI” or “VI” curves are preferred.
Other curves may be used where the downstream protection does not suit the use of the
preferred curves.
High Set Earth Fault Elements - Where available, high set Earth Fault elements may be
used, provided that the element is not capable of reaching to any downstream recloser
under maximum fault conditions or operating due to feeder energisation inrush. In order to
prevent malgrading with distribution transformer fuses, a 300ms definite time delay setting
is preferred over an instantaneous setting.
7.1.2
Feeder Sensitive Earth Fault (SEF) Protection
Feeder SEF protection should be set as follows:
SEF pickup: The SEF pickup shall be set between 4A and 10A primary
SEF time delay: The SEF time delay shall have a maximum of 10seconds delay and a
minimum of 5seconds. This delay shall ensure a time grading margin of at least
0.5seconds over downstream SEF relays.
*Note: Sensitive Earth Fault Protection shall not be applied to a feeder to which an unisolated single wire earth return (SWER) line is connected. Sensitive Earth Fault Protection
shall not be applied to any underground distribution systems.
7.1.3
Underfrequency Protection
Where required, underfrequency settings for distribution feeders shall be determined by
AEMO, as per S5.1.10.2 of the National Electricity Rules.
7.2
Shunt Capacitor Protection
7.2.1
Capacitor Components and Types
A capacitor bank can be broken down into the following components:
Each bank is comprised of one or more stages. A stage is basically a portion of the
capacitor bank which can be energised separately to the rest of the bank via a
contactor
Each stage consists of a number of individual capacitor cans or units
A can or unit is the smallest physical capacitor component in the bank. Each can
typically consists of parallel and/or series combinations of smaller, lower voltage
capacitors; however these are sealed within the can. A can may be rated to the
system voltage for lower voltages (22kV or less) or it may be placed in series with
other capacitors to be used on higher voltages.
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Shunt capacitors can be broadly put into two main types:
Fused capacitors - These banks usually consist of series and/or parallel combinations
of individual capacitor cans per phase. Each unit is protected by its own fuse.
Operation of a single fuse does not necessarily render the entire bank inoperative;
however multiple failures can cause excess voltages to be impressed on the remaining
cans
Unfused or Fuseless banks - These banks consist of one or more series strings of cans
per phase. Should the dielectric in a can fail, it is designed to weld the electrodes
together, such that it can safely carry the string current. This also will impress higher
voltages on the remaining cans.
The shunt capacitor configurations common within Essential Energy are:
Ungrounded Double Star - Each stage is divided into two star connected half-stages.
The neutrals of these half-stages are connected together, but are not earthed. CT‟s
are usually placed between the neutrals. This is the preferred arrangement for all new
capacitor banks
Grounded Star - Each can (or combination of cans) is connected to a phase and to
earth. CT‟s are sometimes placed on the earth connections. This is a legacy
arrangement within Essential Energy‟s network.
7.2.2
Capacitor Protection
Whilst the actual protection implemented on a particular bank may vary depending upon
capacitor type or configuration, the basic protection principles remain the same. These
principles are:
Protection of a bank against short circuit - This is often taken care of by the fuses in a
fused bank. Paper dielectric capacitors are known to produce gas under short circuit
conditions, which can lead to tank rupture and damage to healthy capacitors. Some
capacitor manufacturers provide Tank Rupture Time Current Curves which are used to
ensure the fuse selected will prevent rupture. Grounded capacitors are most
susceptible to tank rupture as the prospective fault currents are higher
Protection of the bank against overload (overheating) - This can occur when the bank
is subjected to prolonged excessive currents which have the effect of increasing can
temperature and reducing dielectric life. These currents are typically due to harmonics
or a high system voltage.
Protection of individual cans against overvoltage - Capacitors are sensitive to
overvoltages. Although quoted values vary, it is generally stated that capacitors
should not be subjected to greater than 110% of rated* volts continuously, otherwise
dielectric life will suffer. As substation bus voltages can normally be expected to be in
this vicinity, the failure of one or more cans may place an excessive voltage on the
remaining cans.
*The rated volts may vary between manufacturers. Some use the highest operating voltage
(“Um” as per AS1824.1 eg 24kV); others use the nominal system voltage (eg 22kV). Unless
otherwise known, the nominal system voltage should be used.
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7.2.3
CEOP8002
Capacitor Overcurrent and Earth Fault Protection
CT Ratio chosen – CT ratio should be chosen so that rated secondary current does not
flow at primary current LESS than 150% of the rated current of the capacitor bank
Overcurrent pickup – The primary overcurrent pickup should be set as follows:
o
To the manufacturer‟s recommended setting
o
In the absence of recommended settings then the pickup should be set as near
as practical to 140% of capacitor rated current. This is due to the fact that
capacitor banks are generally rated for 130% of nameplate current
Overcurrent timing – The relay overcurrent timing shall be set as such:
o
Above any individual can or bank fuses (where installed). A time grading
margin of 200ms min, 300ms preferred should be used
o
Below upstream devices, up to the maximum fault level that the capacitor
overcurrent relay and upstream device shall simultaneously see for a fault.
The following time grading margin between the capacitor overcurrent relay and upstream
devices should be used:
If the upstream relay is electronic - 300ms minimum, 400ms preferred
If the upstream relay is an induction disk type - 400ms minimum.
To ensure that the overcurrent relay will not operate during capacitor energisation. For a
numerical relay, a minimum tripping time of greater than 2 cycles is sufficient to provide
security against spurious tripping. Hence a TMS of 0.1 is usually sufficient.
High Set Overcurrent - If used, high set overcurrent elements in Numerical relays
must have at least a two cycle delay. It is recommended that high set elements not
be used unless recommended by the capacitor bank manufacturer
Earth Fault pickup – The primary Earth Fault pickup should be set as follows:
o
To the manufacturer‟s recommended setting
o
In the absence of recommended settings then the pickup should be set to 20%
of the capacitor bank current. Particular care should be taken when setting the
Earth Fault pickup for a grounded bank, as grounded capacitors will act as a
path for return fault current for nearby earth faults - refer to earth fault timing
Earth Fault timing – The relay Earth Fault timing shall be set as such:
o
Above any individual can fuses (where installed) - note that grading over entire
bank fuses is not required due to the high settings that would be needed. A
time grading margin of 200ms min, 300ms preferred should be used.
o
Below upstream devices, up to the maximum fault level that the capacitor
Earth Fault relay and upstream device shall simultaneously see for a fault.
The following time grading margin between the capacitor Earth Fault relay and upstream
devices should be used:
If the upstream relay is electronic - 300ms minimum, 400ms preferred
If the upstream relay is an induction disk type - 400ms minimum
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To ensure that the Earth Fault relay will not operate during capacitor energisation. For
a numerical relay, a minimum tripping time of greater than 2 cycles is sufficient to
provide security against spurious tripping. Hence a TMS of 0.1 is usually sufficient
Grounded capacitors can act as a return path for earth fault currents. The capacitor
earth fault relay shall be set to time grade over any circuit Earth Fault protection for
an earth fault on that circuit. Due to the relatively low fault currents flowing in the
capacitor compared to the feeder, time grading shall not be usually difficult to achieve.
7.2.4
Capacitor Unbalance Protection
Unbalance Protection - Unbalance protection is provided to detect an unbalance
condition. This is in order to protect cans from excessive voltage and also to prevent
unbalanced voltages from occurring on the busbar. Unbalance protection shall be set as
follows:
As per manufacturer‟s recommendations.
In the absence of manufacturer‟s setting, the following should apply:
Where the capacitor is configured such that the removal of one or more cans may
place additional voltage stress on the remaining capacitors, the TRIP level should be
set to the unbalance current value (for the protected stage) which corresponds to a
10% increase in voltage across any remaining can (compared to a fully balanced
system). The TRIP should be delayed between 0.5 and 2.0 seconds in order to
prevent spurious tripping. The ALARM value should be set to 50% of the TRIP value
and be delayed by 10 seconds
Where the capacitor is configured such that the removal of one or more cans will NOT
place additional voltage stress on the remaining capacitors, the TRIP level should be
set for a current equivalent to 15% of the rating of the protected stage. The TRIP
should be delayed between 0.5 and 2.0 seconds in order to prevent spurious tripping.
The ALARM value should be set to 50% of the TRIP value and be delayed by 10
seconds.
Unbalance CT’s - The class of Unbalance CT‟s shall be selected as follows:
To be accurate for the low levels at which the relays are anticipated to operate. For
this reason measurement class CT‟s may be used in this application
The CT shall be capable of withstanding the primary prospective fault level that it may
be subjected to. This is especially the case for wound primary CT‟s.
7.2.5
Capacitor Overvoltage Protection
Overvoltage protection - Where used, capacitor overvoltage protection should be set to
operate at 120% of the capacitor rated volts and with a delay of 10 seconds.
7.3
Frequency Injection System Protection
Frequency injection (FI) is typically injected on the distribution or subtransmission busbar
via an isolating transformer.
7.3.1
FI Set Overcurrent and Earth Fault Protection
CT Ratio chosen – CT ratio should be chosen so that rated CT secondary current does not
flow when a primary current of LESS than 150% of the rated primary current of the FI plant
flows through the CT primary.
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Overcurrent pickup – The primary overcurrent pickup should be set as follows:
To the manufacturer‟s recommended setting
In the absence of recommended settings the overcurrent relay should be set to 120%
of the rated current of the FI plant (as most numerical relays use 50Hz band pass
filtering, the relay do not typically respond to currents at the FI frequency)
The overcurrent relay pickup setting should be capable of seeing any terminal fault on
the lower voltage side of the injection transformer, with an Operating Factor of 2.0.
Overcurrent timing – The relay overcurrent timing shall be set as such:
To the manufacturer‟s recommended setting
In the absence of recommended settings the overcurrent relay timing should be set to
operate for faults on the lower voltage terminals of the injection transformer in not
more than 1.0sec
Below upstream devices, up to the maximum fault level that the FI set overcurrent
relay and upstream device shall simultaneously see for a fault
The following time grading margin between the FI Set overcurrent relay and upstream
devices should be used:
o
If the upstream relay is electronic - 300ms minimum, 400ms preferred
o
If the upstream relay is an induction disk type - 400ms minimum.
Above downstream protective devices (if fitted), up to the maximum fault level that
the FI set overcurrent relay and downstream device shall simultaneously see for a
fault
The following time grading margin between the FI Set overcurrent relay and upstream
devices should be used:
If the FI set relay is electronic - 300ms minimum, 400ms preferred
If the FI set relay is an induction disk type - 400ms minimum
The overcurrent relay shall not operate for injection transformer energising current.
Earth Fault pickup – The primary Earth Fault pickup should be set as follows:
To the manufacturer‟s recommended setting
In the absence of recommended settings the overcurrent relay should be set to 20%
of the rated current of the FI plant or 10A, whichever is the greater.
Earth Fault timing – The relay Earth Fault timing shall be set as such:
Below upstream devices, up to the maximum fault level that the FI set Earth Fault
relay and upstream device shall simultaneously see for a fault
The following time grading margin between the capacitor Earth Fault relay and
upstream devices should be used:
If the upstream relay is electronic - 300ms minimum, 400ms preferred
If the upstream relay is an induction disk type - 400ms minimum
To ensure that the relay does not operate during isolating Transformer energisation.
An IEC 60255 curve time multiplier of 0.1 or more should be adequate.
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7.4
Distribution Automatic Reclose
7.4.1
Automatic Reclose Justification
CEOP8002
Because a large proportion of faults are of a transitory nature, it is normally an advantage
to attempt to reconnect a distribution system that has been isolated by protection operation
after a fault, if this is likely to restore supply to the distribution system without undue risk
to personnel, livestock, or plant.
Sensitive Earth Fault protection
The type of fault covered by this type of protection is rarely, if ever transient in nature and
often may be a danger to the general public.
Sensitive earth fault protection shall not be used to initiate an automatic reclose operation.
Distribution feeders
For the purpose of automatic reclose, distribution feeders can be categorised into overhead
or underground types of feeders.
Overhead distribution feeders
An overhead distribution feeder is a feeder that is predominantly overhead in construction;
it may have some small sections of underground construction.
Overhead distribution feeders can be further categorised into the following groups:
Urban overhead distribution feeders
Any overhead feeder that supplies predominantly urban areas, i.e. towns, villages etc
Rural overhead distribution feeders
Any overhead feeder that supplies predominantly rural areas, i.e. farms, hamlets etc
Industrial overhead distribution feeders
Any overhead feeder that supplies predominantly industrial areas, i.e. industrial parks
etc. Automatic reclose should not be implemented. Where a feeder traverses a large
section of rural area which may be subject to transient faults, automatic reclose may
be considered
Underground distribution feeders
An underground distribution feeder is a feeder that is predominantly underground in
construction; it may have some small sections of overhead construction
Faults on underground feeders are usually not transient in nature; therefore automatic
reclose shall not be implemented on underground distribution feeders.
7.4.2
Automatic Reclose Attempts
The majority of transient faults will be cleared by a single tripping operation.
Automatic reclose shall be disabled prior to:
live line work
any manual close of a CB, including re-energising plant following maintenance and
energising plant while sectionalising to locate a fault.
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Automatic reclose shall not be used for customer owned lines or for lines dedicated to one
customer unless authorised by the customer.
General statistics indicate a 70% successful reclose when slow reclosing is used, a further
5% on a second attempt and 1% on the third attempt. The possible success of reclosing
against potential permanent damage to equipment needs to be considered when applying
reclose. Only two reclose attempts are recommended unless used in conjunction with
sectionalisers.
Reclose dead time settings shall include allowance for:
likely risk to personnel on or arriving at the scene
switch operating mechanism reset and stabilise time, including contact cooling times
after passing fault current
relay reset time
likely effects on customer equipment of a restoration of supply after a short outage
effects on equipment, including risk of damage from the mechanical and electrical
effects of repeated fault current and trapped charges.
Urban overhead distribution feeders
Due to safety concerns involving automobile accidents with fallen conductors a maximum of
one reclose attempt should be used on urban overhead distribution feeders, set at 10s.
Rural overhead distribution feeders
There should be two reclose attempts allowed on rural overhead distribution feeders, except
where sectionalisers requiring additional reclosers are installed. These should be set to 10s.
The accumulated trip and reclose times should not be greater than 25s due to possible
safety implications.
Field reclosers
The same principle detailed above should generally be applied to field reclosers.
7.4.3
Reclaim Time
Reclaim time must in all cases be longer than the operating time of any protection that may
initiate an auto-reclose operation. (See 1 below)
Reclaim time settings must consider the mechanical limitations of the CB and protection
relays, which include but are not limited to:
switch operating mechanism reset and stabilise time, such as spring charge time
required to set up CB for a normal trip-close-trip sequence
thermal limits requiring cooling time between successive fault current incidents in
equipment
time for electromechanical relays to reset.
Refer to Attachment A for Total Fault Clearing Time calculations, methods and Terms.
1
This can be quite long for an Extremely Inverse IDMT overcurrent relay operating at about 120% of its nominal
setting.
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7.5
CEOP8002
Automatic Field Reclosers
An automatic recloser is a self-contained device with the necessary circuit intelligence to
sense overcurrents, to time and interrupt the overcurrents, and to reclose automatically to
re-energize the line. If the fault should be “permanent” the recloser will “lock open” after
the preset number of operations (usually one to four) and thus isolate the faulted section
from the main part of the system.
Modern automatic reclosers enjoy the feature that they can employ different curves for each
reclose attempt. If there are line section fuses downstream of the recloser it is beneficial to
have at least one fast shot to provide some protection for the fuses for a transient fault.
Reclosers Classifications
Automatic circuit reclosers are classified on the basis of single or three phases, Hydraulic;
Electronic or Microprocessor controls, Oil or vacuum interrupters.
7.5.1
O/C, E/F and SEF Protection on line Reclosers
When selecting reclosers for field application, consideration should be given to ensure the
unit is suitably rated for the interrupting capacity at the location being installed.
Overcurrent Protection covering phase and earth faults shall be set to detect faults on the
line in the recloser‟s zone. The line recloser shall meet the same requirements as laid down
in the distribution part of the guideline on Overcurrent and Earth Fault for grading and
backup (including the setting of SEF protection).
Inrush Restraint
Used to temporarily prevent the recloser tripping on the initial close due to inrush currents.
Before implementing inrush restraint, consideration should be given as to the need for its
implementation and the setting required, which will be dependent on the load type and
overcurrent and earth fault protection settings in the recloser. It is important to note that if
turned on, inrush restraint may become active in times of very light load.
Typical settings for this function are 4 x full load current with a time setting of 0.15 second.
Cold Load Pickup
Used to temporarily prevent higher than normal load currents causing a trip due to loss of
diversity when switching on to a system after an extended outage. Cold load pickup
temporarily increases recloser protection pickup settings It is recommended to turn on
cold load pickup only where necessary. Various reclosers apply this principle using
different methods of application. It is important to understand the particular implementation
in the recloser being set (refer to manufacturer‟s literature). It is important to note that if
turned on in reclosers cold load pickup may become active in times of very light load.
If cold load pickup is implemented consideration should be given to the impact on backup
and primary operating factors while cold load pickup is active.
Typical settings for this function are 1.5 - 2 x full load current and a time setting of 120
minutes.
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7.5.2
CEOP8002
Coordination between Reclosers and Recloser in Series
Recloser to recloser coordination is achieved by time-current grading primarily by the
selection of different series trip-coil rating in hydraulic reclosers, or different minimum-trip
current values in electronic reclosers and determination of the recloser time-current
characteristics.
Grading margins starting from the source:
Electronic to hydraulic 300ms
Electronic to Electronic 300ms
Hydraulic to hydraulic 400ms
Hydraulic to electronic 400ms.
Dead times should take into account slow reset times of hydraulic reclosers and margins
between hydraulic devices should be increased with the number of reclose attempts.
Where fuse saving schemes are employed that use fast/slow curves upstream reclosing
devices shall have sequence control enabled.
7.5.3
Coordination between Recloser and Sectionaliser in Series
Installation of a sectionaliser does not affect the operating factor required at the recloser.
7.5.4
Coordination between Reclosers and Fuses in Series:
Coordination will depend on the number of shots set on the recloser for the downstream
fuses.
In rural areas where transient faults may be a problem, reclosers are normally set to give at
least one instantaneous trip, so if the fault is of a transient nature, it can be cleared without
blowing the fuse and interrupting supply.
For optimum coordination between a recloser and fuse their characteristics should be such
that whilst all transient faults would be cleared by one or more instantaneous recloser
operations without the fuse blowing, permanent faults would blow the fuse before the
recloser reached the lockout condition.
This ideal is not always attainable for all faults values, yet a reasonable compromise can
often be achieved by examination of recloser and fuse characteristics where ideally the fuse
characteristic should fit between the instantaneous and the delay tripping for the recloser.
Where fast curves are employed on reclosers to protect fuses during transient faults, a 1.5
times operating factor should be used for fault detection.
With electronic reclosers when using instantaneous trips then a minimum time (usually 0.1
sec) can be considered to prevent unnecessary spurious trips and provide protection
stability e.g. from indirect lightning surges etc.
Backup protection is not required for high voltage fuses.
Consideration should be given to fuse element heating when coordinating with fuses, the
grading margin will decrease for source side fuses with subsequent reclosers, an increased
grading margin and/or reclose times should be considered to ensure grading, the grading
margin for load side fuses will be increased by successive reclosers.
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1000.0
0
15A
SLOW
20A
SLOW
100.0
0
15A
FAST
20A
FAST
10.0
0
Time in
Second
s
DELAYED
CURVE
1.0
0
INSTANTANEOUS
0.1
0
0.0
1
1
10
100
1,000
10,000
Coordination between Reclosers and Fuses
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7.5.5
CEOP8002
Coordination between Fuses and Downstream Reclosers
It is common on isolated SWER systems and rural zone substations for fuses being the
primary SWER isolation or zone substation transformer protection, with downstream
reclosers used to clear faults on the SWER or 3-phase distribution network respectively.
The source side fuses will normally be rated to provide protection to the transformer, and
will basically determine what the combination of recloser curves used, so that the fuse does
not interrupt the circuit for any fault current on the recloser. The recloser‟s modified delayed
curve must be faster than the fuse‟s minimum melt curve.
For the maximum available recloser fault current, the fuse minimum melting time must be
greater than the average clearing time of the recloser delayed curve, multiplied by a specific
factor “K”.
A comparison of the time-current curves of the fuse and recloser will require that either the
fuse or the recloser curves to be shifted horizontally on the current axis (adjusted for the
same voltage level). Since the fuse size is generally determined by the transformer rating, it
is usually easier to shift the fuse curve and compare to the different recloser curves.
Typical K factors for source side fuses and load side reclosers, used to multiply the time
values of the delayed curve (B, C, D for Cooper reclosers).
Reclosing time
(ms)
400
500
830
1,500
2,000
4,000
10,000
Two-fast, Two slow
sequence (2A 2B)
2.7
2.6
2.1
1.85
1.7
1.4
1.35
One-fast, three-slow
sequence (1A3B)
3.2
3.1
2.5
2.1
1.8
1.4
1.35
Four-delayed sequence
(4B)
3.7
3.5
2.7
2.2
1.9
1.45
1.35
The intersection of the K-factor adjusted delayed curve with the fuse minimum-melting time
curve determines the maximum coordinating current.
7.5.6
Basic Coordination Principles to be Observed
The load-side device must clear permanent or temporary faults before the source side
device interrupts the circuit (fuse link) or operates to lockout (recloser)
Outages caused by permanent faults must be restricted to the smallest section of the
distribution system.
These principles primarily influence the selection of curves and the sequences of operation
of both source side and load side devices, and the general location of these devices on the
distribution system. The placements of a number of devices to restrict outages to the
“smallest section of the system” are determined by individual cases and the protection
guidelines.
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7.5.7
CEOP8002
Basic Guidelines for the Location of Reclosers:
Principal Fault Causes
The principal fault causes in Essential Energy are lightning, birds, branches and bark in
roughly that order
Remote controlled electronic reclosers allow protection to be customised to these fault
types to reduce fire risk and outage time.
Advantage of remote controlled electronic reclosers
Remote controlled electronic reclosers have the following advantages:
Curves can be shaped to give fast clearing of high currents - minimizes fire risk
Curves can be shaped to allow cold start inrush to pass - allows lower pickups and
faster operation
Can be loaded to 75% of Trip Current - allows higher loads on long feeders
Can customize dead times to fault types - minimizes momentary outages
Can read trip current remotely - gives distance to fault and speeds restoration
Trip sequence advance feature - minimizes fire risk with stuck recloser down line
Cold start inrush feature - allows restoration of heavily loaded feeders without
sectioning
Can shape curves to any recloser or fuse - allows better coordination up line and down
line
Sensitive ground fault protection - can be graded to minimize outage areas.
7.5.8
Application Rules for Reclosers
Reclosers should be located to segment the system to minimise customer exposure to
faults.
Reclosers should be located to ensure fault coverage and to meet backup requirements.
Remote controlled reclosers should be considered in troublesome locations.
Excessive use of series reclosers can cause grading problems, and sectionalisers should be
considered. It is recommended to not use more than three reclosers in series on any one
line section.
Reclosers should be the minimum requirement for new single customer spurs above 1MVA
as the connection point device.
7.6
Line Fuses
Fuses are the most basic protection devices available for overcurrent protection on a
distribution system. Their primary function is to serve as inexpensive weak links in the
circuit-links that open to clear (interrupt) overcurrent and protect equipment against
overload and short circuit. They can also be used as line sectionalising.
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7.6.1
CEOP8002
Fuse to Fuse Coordination
Discrimination: Fuse to fuse 100ms.
Backup protection is not required for high voltage fuses.
All fuses operate in the same way. A conductor of limited cross-section is heated by current
passing through it until it melts. This takes time, represented in time/current
characteristics for the fuse. On melting, a break is caused in the element, at which an
electrical arc is established. The arc burns in the fuse until the current returns to zero. Thus
there are two stages in fuse operation:
The pre-arcing time (time/current characteristics)
The arcing time.
The arcing behaviour is different for small, large and intermediate overcurrents.
Where possible an operating factor of 3.0 should be used when selecting fuses. Note that
fuse continuous rating is typically above nominal rating.
7.6.2
Principles of Operation of Fuses
Low overcurrents
At low overcurrents, the fuse breaks initially at just one point – the „M‟ effect spot. This
single arc needs to lengthen before the voltage developed across the fuse is large enough to
allow extinction. It lengthens by burning away elements materials. The longer the time
taken to do this, the more probable is the catastrophic failure.
High overcurrents
The fuse element vaporizes at all its constrictions. This produces a voltage drop sufficient
to rapidly reduce the current to zero.
Current-time curves for both pre-arcing time and total operating time are published for
higher overcurrents, but there is a large tolerance band for both, which gets wider (as a
proportion of the total operation time) as the current increases. This is because both prearcing and arcing times depend heavily on the degree of DC offset current in the fault,
which itself is determined by the point–on–wave of the voltage where the fault occurs (an
unpredictable variable). For this reason „virtual time‟ curves are used at high currents,
when operating times are less than about 0.1 sec.
The virtual time curves are not intended, therefore, to indicate actual operating times, but
serve as a guide to grading fuses. The virtual total operating time of the minor fuse lie
below the virtual pre-arcing time of the major fuse.
Intermediate overcurrents
The worst case energy dissipation in fuses may occur at intermediate currents. The
inductive energy dissipated by the arc, 0.5LI², does not continuously increase with
increasing prospective current, but peaks and then decreases.
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The maximum Ldi/dt voltage developed across a fuse during operation is a function of the
element length and design (number of construction) rather than circuit inductance. This
voltage is limited by design and is fairly constant for any given fuse in a circuit up to its
voltage rating. Above this voltage, the peak voltage may rise as the wider parts of the
element disintegrate (due to persistent arcing caused by the higher circuit voltage) and
from globules. The moral of this is: do not use a fuse in a circuit that exceeds its voltage
rating!
7.6.3
Grading of Fuse to Fuse of the Same Voltage
The method of ensuring coordination is to inspect current-time curves, which generally
include minimum pre-arcing time and maximum clearing time. Such curves are only
available on distribution circuits. Time curves permit fuses of different manufacturers and
designs to successfully cooordinate. We simply need to ensure that the minimum prearcing time of the major fuse is greater than the maximum clearing time of the minor fuse,
up to the maximum fault current that can be seen by both. This maximum current
condition is a fault just downstream of the minor fuse.
An acceptable rule for coordinating fuse links is that the maximum clearing time of the
protecting link should not exceed 75% of the minimum melting time for the protected fuse.
This assures that the protecting fuse will interrupt and clear the fault before the protected
fuse is damaged in any way.
7.6.4
Types of Distribution Fuses
Expulsion type fuses are the most commonly used fuse in distribution systems, the
main duty of the fuse is to protect equipment against overcurrent and over load of the
system, secondary to indicate the fuse has been blown by dropping out of its inservice position
Powder filled fuses
Vacuum fuses.
Reference should be made to the Distribution Fusing Policy CEOS5099 for the correct sized
fuses.
8
PROTECTION COORDINATION
In normal cases, a minimum 400ms shall be allowed for coordination between the operating
times of protection and upstream backup protection of the electro-mechanical type
(Main/Backup). In cases, where the upstream scheme utilises electronic devices, this time
may be reduced to 300ms. In special cases, the consideration of the characteristics of the
protection relays and the switching devices may allow a variation in coordination times.
9
RECORDS
The Essential Energy employees associated with protection shall be responsible for the
recording, storage and maintenance of all protection records. Details of all the current and
historic settings, tripping schemes, Instrument transformer ratios, reclose times,
configurations, software files, firmware and software versions, calculations and analysis
details etc of all transmission, subtransmission and distribution protection equipment and
devices, should be stored. All Essential Energy employees associated with planning,
protection, control and maintenance should have read access to current device data.
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CEOP8002
Our organization‟s records are our protection system memory, providing evidence of actions
and decisions and representing a vital asset to support our daily functions and operations.
10
HIGH VOLTAGE CUSTOMERS
The customer is to provide a protective system approved by Essential Energy to disconnect
their equipment from the supply in the event of a fault on their equipment.
All protection settings shall provide suitable discrimination with Essential Energy‟s
system protection
All protective equipment must be maintained to an industry recognised standard
Fuses can be used as the connection point for customers <1MVA. Customers => than
1MVA, a recloser is to be used as the minimum connection point device to ensure that
other Essential Energy customers are not affected by faults in the HV customer‟s
network.
11
GENERATORS
All Generation proposed for installation on Essential Energy‟s Network shall be assessed on
an individual case basis considering the type of Generator proposed and the proposed
location on the network.
Reference should be made to the Generation Connection guidelines CEOP8012 when
checking/applying protection for these systems.
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12
CEOP8002
ATTACHMENT A – TOTAL FAULT CLEARING TIME
CALCULATIONS, METHODS AND TERMS
Figure 1 and Figure 2 show the method of calculation of Total Clearing Time and clarify
some of the terms used.
Figure 1: Permanent Fault Trip Sequence with One Reclose
Fault Detected
Trip
Reclose
Trip to Lockout
On
Off
Fault
Clearance
Time
Dead
Time
Fault
Clearance
Time
Total Clearing Time
Figure 2 Permanent Fault Sequence with Three Recloses
Fault Detected
Reclose
On
Trip
Trip to Lockout
Reclose
Trip
Trip
Reclose
Off
FCT
DT
FCT
DT
FCT
DT
FCT
Total Clearing Time
FCT = Fault Clearance Time
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DT = Dead Time
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13
CEOP8002
REFERENCES
CEOP1096 - Information Security Sensitivity Labelling and Handling
“Code of Minimum Electrical Protection”, C (b) 5 - 1968, Electricity Supply Association of
Australia
ENA C(b)1-2006 : Guidelines for design and maintenance of overhead distribution and
transmission lines.
“Guide to the Application of Autoreclosing to Radial Overhead Lines Supplying Urban and
Rural Areas”, D (b) 12 - 1991, Electricity Supply Association of Australia
14
REVISIONS
Issue Number
Section
2
All Sections
To numerous to list
2
All Sections
Updated to current Essential Energy template
3
4
All
Details of Changes in this Revision
Update to rebrand to Essential Energy. Updated Capacitor
Bank section 5.9, Added 6.1.8 Broken Conductor Logic,
Inserted new 6.3 Line Differential protection, Updated
7.1.1 Feeder Overcurrent and Earth fault
protection,Updated 7.1.2 SEF Protection,Added 7.1.3
Distribution Underfrequency Schemes, Updated 7.5.1
Inrush restraint and Cold load Pickup, Section 11
generators Reduced to a reference to CEOP8012.
Updated to reflect the organisational restructure
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