Transmission Line Protection Asset Management

Transcription

Transmission Line Protection Asset
Management Plan
D09/34013
Issue 3.0, March 2014
Approved
Transmission Line Protection Asset Management Plan
Contact
This document is the responsibility of the Network Performance and
Strategy Team, Transend Networks Pty Ltd, ABN 57 082586 892.
Please contact the Network Performance and Strategy Manager with any
queries or suggestions.
Next Review
This document has a normal scheduled review frequency of 2.5 years
from date of last approval.
Responsibilities
•
Implementation
All Transend staff and contractors.
•
Compliance
All group managers.
Minimum Requirements
The requirements set out in Transend’s documents are minimum
requirements that must be complied with by Transend staff, contractors,
and other consultants.
The end user is expected to implement any practices which may not be
stated but which can be reasonably be regarded as good practices
relevant to the objective of this document.
This document is protected by copyright vested in Transend Networks Pty Ltd. No part of the document may
be reproduced or transmitted in any form by any means including, without limitation, electronic,
photocopying, recording or otherwise, without the prior written permission of Transend. No information
embodied in the documents that is not already in the public domain shall be communicated in any manner
whatsoever to any third party without the prior written consent of Transend. Any breach of the above
obligations may be restrained by legal proceedings seeking remedies including injunctions, damages and
costs.
Page 2 of 54
Record of revisions
Section number
Detail
2.3.1
Updated the reference to the latest SKM asset valuation report
Figure 12
Figure 14 was moved to section 3.2 and has become figure 12
3.2
Updated wording to support a graph summarising the asset condition
Figure 13
Was figure 12 but now figure 13
5.2
Wording on asset risk has been modified and old figure 13 deleted
Page 3 of 54
Table of contents
Executive summary ............................................................................................................................ 7
1
2
3
General ...................................................................................................................................... 8
1.1
Introduction .................................................................................................................. 8
1.2
Purpose ......................................................................................................................... 8
1.3
Scope ............................................................................................................................ 8
1.4
Objectives ..................................................................................................................... 8
1.5
Strategic context ......................................................................................................... 10
1.6
Asset management information system ...................................................................... 11
Transmission line protection description ............................................................................. 12
2.1
Related Transend documents...................................................................................... 12
2.2
Asset type ................................................................................................................... 13
2.2.1
Protection schemes ..................................................................................................... 13
2.2.2
Technology types ....................................................................................................... 14
2.2.3
Technology population ............................................................................................... 15
2.3
Age profile .................................................................................................................. 16
2.3.1
Economic life ............................................................................................................. 18
2.4
Scheme functionality .................................................................................................. 19
2.4.1
Main protection devices ............................................................................................. 19
2.4.2
Bay controller ............................................................................................................. 20
2.5
Makes and models ...................................................................................................... 20
2.5.1
Electromechanical devices ......................................................................................... 20
2.5.2
Static devices .............................................................................................................. 21
2.5.3
Microprocessor devices .............................................................................................. 23
Condition monitoring practice .............................................................................................. 25
3.1
Defect management practices ..................................................................................... 26
3.2
Asset Condition Summary.......................................................................................... 26
3.2.1
Electromechanical ...................................................................................................... 27
3.2.2
Static ........................................................................................................................... 27
3.2.3
Microprocessor ........................................................................................................... 27
3.3
Special operational and design issues ........................................................................ 28
3.3.1
Operational issues....................................................................................................... 28
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4
5
6
7
3.3.2
Substation design issues ............................................................................................. 29
3.4
Asset compliance ........................................................................................................ 30
Asset Performance .................................................................................................................. 31
4.1
Service obligations for prescribed assets.................................................................... 31
4.2
Service obligations for non-prescribed assets ............................................................ 32
4.2.1
Major Industrial customer connections ...................................................................... 32
4.2.2
Hydro Tasmania ......................................................................................................... 32
4.2.3
Other generation sources ............................................................................................ 32
4.3
Key Performance Indicators (KPI) ............................................................................. 32
4.3.1
Protection performance .............................................................................................. 32
4.3.2
Disturbance recording ................................................................................................ 33
4.3.3
Auto-reclose ............................................................................................................... 33
4.3.4
Fault location .............................................................................................................. 33
4.3.5
Performance summary................................................................................................ 33
4.4
Benchmarking ............................................................................................................ 34
4.4.1
ITOMS benchmarking ................................................................................................ 35
Risk .......................................................................................................................................... 36
5.1
Business risks ............................................................................................................. 37
5.2
Asset risk .................................................................................................................... 37
5.2.1
Criteria for calculating asset risk ................................................................................ 37
5.2.2
Consequence of protection failure .............................................................................. 38
5.2.3
Intangible consequences ............................................................................................. 38
5.2.4
Likelihood .................................................................................................................. 38
5.2.5
Severity....................................................................................................................... 39
5.2.6
Failure type ................................................................................................................. 39
5.3
Risk analysis and mitigating strategies ...................................................................... 40
5.4
Monitoring and review ............................................................................................... 40
Demand analysis ..................................................................................................................... 41
6.1
Planned augmentation ................................................................................................ 41
6.2
Asset specific implications ......................................................................................... 41
Lifecycle management plan ................................................................................................... 41
7.1
Issues summary .......................................................................................................... 41
7.2
Maintenance plan ....................................................................................................... 42
7.2.1
Preventive maintenance .............................................................................................. 42
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8
9
7.2.2
Corrective maintenance .............................................................................................. 42
7.2.3
Technical support ....................................................................................................... 42
7.3
Capital plan................................................................................................................. 43
7.3.1
Scheme replacement strategies ................................................................................... 43
7.3.2
Scheme replacement program .................................................................................... 44
7.3.3
Standard scheme development ................................................................................... 45
7.3.4
Standardisation ........................................................................................................... 45
7.4
Disposal plan .............................................................................................................. 46
Financial Summary ................................................................................................................ 46
8.1
Operational expenditure ............................................................................................. 46
8.2
Capital expenditure..................................................................................................... 46
8.3
Investment evaluation................................................................................................. 46
Appendix A – Poor condition transmission line protection devices ................................... 47
List of figures
Figure 1
Asset management document framework .................................................................. 11
Figure 2
Transmission line protection device technology types per scheme ........................... 15
Figure 3
Technology types per substation ................................................................................ 16
Figure 4
Transmission line protection device age profile......................................................... 17
Figure 5
Transmission line protection age profile per scheme type ......................................... 18
Figure 6
110 kV transmission line protection electromechanical devices ................................ 21
Figure 7
220 kV transmission line protection electromechanical devices ................................ 21
Figure 8
110 kV transmission line protection static devices .................................................... 22
Figure 9
220 kV transmission line protection static devices .................................................... 23
Figure 10
110 kV transmission line protection microprocessor devices .................................... 24
Figure 11
220 kV transmission line protection microprocessor devices .................................... 25
Figure 12
Transmission line protection devices condition summary ......................................... 28
Figure 13
ITOMS Protection SCADA and communications benchmarked
performance chart ....................................................................................................... 35
List of tables
Table 1
Transmission line protection device technology types per scheme ........................... 15
Table 2
Transmission line protection replacement program ................................................... 44
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Executive summary
This document is Transend’s asset management plan for its population of transmission line
protection for the following ten years. The objective of this plan is to maintain and minimise
business risk to acceptable limits by achieving reliable asset performance at minimal life-cycle cost.
The strategies identified in this asset management plan have been developed taking into account
past asset performance, good electricity industry practice and the need for prudent investment to
minimise life-cycle costs and optimise transmission line protection performance.
The condition assessment, maintenance practices and spares holdings for transmission line
protection have been revised where appropriate to improve transmission line protection reliability
and optimise transmission system performance. With the introduction of newer self-diagnostic
devices, requiring reduced maintenance and testing frequencies, maintenance costs are expected to
decline.
A comprehensive capital investment plan has been developed to address the risk, design and
performance issues associated with the transmission line protection population and to improve
transmission system performance. It is also Transend’s strategy to achieve a higher degree of
standardisation to decrease the diversity in device type and make, without sacrificing equipment
functionality. This strategy will also reduce training cost incurred by maintenance staff to
familiarise with new devices.
The plan presents a replacement program for the period 2012 to 2022. The replacement program
recommends that obsolete electromechanical and static protection devices be replaced progressively
with microprocessor based schemes, and where appropriate these works be integrated with other
capital works. This asset management plan presents supporting information for such a program and
provides evidence that the replacement program will mitigate the business risks presented by the
existing transmission line protection population and minimise future maintenance costs. In addition,
the program will rationalise the number of transmission line protection types and designs through
equipment standardisation, leading to a reduction in transmission line protection spares inventory
and simplified contingency planning and fault response processes.
The risk to system security and transmission system performance degradation, by persisting with
difficult to maintain equipment is also a compelling reason not to delay planned transmission line
protection asset replacements.
The successful implementation of the strategies detailed in this plan will minimise Transend’s
business risk by enhancing transmission line protection performance. The improved maintenance
practices will significantly reduce expenditure requirements and enhance transmission circuit
availability, resulting in improved service levels to customers.
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1
General
1.1
Introduction
Transend’s vision is to be a leader in developing and maintaining sustainable networks. In keeping
with this vision the board has identified the strategic performance objectives to improve business
processes, and strategies to improve productivity and efficiency gains, as key goals upon which
overall business performance enhancement must be based.
Transend actions its philosophies for asset management process through asset management plans.
These documents disaggregate the transmission system infrastructure into subsets of like assets. An
asset management plan is available for each subset. This asset management plan is one of a set of
plans that discuss the basis behind Transend’s operating and capital expenditures.
Transend aggregates its network-wide asset management philosophies and action plans into a
biennially published Transmission System Management Plan (TSMP) that is made available to key
stakeholders, including technical and economic regulators.
The strategies identified in this asset management plan have been developed taking into account
past asset performance, good electricity industry practice and the need for prudent investment to
optimise the asset performance.
1.2
Purpose
The purpose of this asset management plan is to define the asset management issues and strategies
specific to transmission line protection for the years 2012 to 2022.
This plan reports on Transend’s assessment of work needed to achieve the service level and
performance goals for the asset class at least life-cycle cost.
1.3
Scope
This asset management plan covers transmission line protection assets for transmission lines
energised at voltages of 110 kV and 220 kV.
1.4
Objectives
The objectives of this asset management plan are to:
a
present an overview of the transmission line protection population;
b
manage business risk presented by the transmission line protection to within acceptable
limits;
c
achieve reliable transmission line protection performance consistent with prescribed service
standards;
d
quantify the risks specific to transmission line protection and identify corresponding risk
mitigation strategies;
e
ensure the effective and consistent management and coordination of asset management
activities relating to the transmission line protection assets throughout their life-cycle;
Page 8 of 54
f
demonstrate that transmission line protection assets are being managed prudently throughout
their life-cycle;
g
ensure asset management issues and strategies as they relate to transmission line protection
are taken into account in decision making and planning; and
h
define future operational and capital work requirements for transmission line protection.
Page 9 of 54
1.5
Strategic context
This asset management plan is part of a suite of documents that supports the achievement of
Transend’s strategic performance objectives and, in turn its mission. The asset management plans
define the issues and strategies relating to transmission system assets and details the specific
activities that need to be undertaken to address the identified issues.
Figure 1 presents Transend documents that support the asset management framework, referenced to
the corresponding IIMM documentation and/or process, adapted to meet Transend’s specific needs.
The diagram highlights the existence of, and interdependence between, strategic, tactical and
operational planning documentation.
Page 10 of 54
Figure 1
1.6
Asset management document framework
Asset management information system
Transend maintains an asset management information system (AMIS) that contains detailed
information relating to the transmission line protection. AMIS is a combination of people processes,
and technology applied to provide the essential outputs for effective asset management, such as:
a
reduced risk;
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b
enhanced transmission system performance;
c
enhanced compliance, effective knowledge management;
d
effective resource management; and
e
optimum infrastructure investment.
It is a tool that interlinks asset management processes through the entire asset life-cycle and
provides a robust platform for extraction of relevant asset information.
2
Transmission line protection description
Transend transmission lines are predominantly overhead conductors energised at 110 kV or 220 kV.
Transend also have two complete underground 110 kV cables and five 110 kV circuits comprising
of overhead and underground cables. Overhead sections of transmission lines are predominantly run
as two circuits per tower although some radial 220 kV transmission lines are run as one per tower.
Transmission line protection assets are required to detect and initiate the isolation of transmission
line faults in order to prevent plant damage and power system instability. The transmission line
protection assets also perform a number of other critical functions required to operate the
transmission system, such as auto re-closing, operational metering, bay level Supervisory Control
and Data Acquisition (SCADA), system synchronisation, backup protection, disturbance recording
and fault locating.
Of the 49 substations and four switching stations that Transend own and operate, there are
189 transmission line protection schemes in service within 43 of these sites.
2.1
Related Transend documents
Technical requirements for new transmission line protection schemes are detailed in the following
standard specification:
D05/15132 Protection of Transmission Line Standard
The following AMIS standard provides information relevant to transmission line protection:
D09/103375 WASP Asset Register – Data Integrity Standard – Scheme
D06/18802 WASP Asset Register – Data Integrity Standard – P&C Device
The routine testing requirements for transmission line protection schemes are detailed in the
following Transend task guides:
D05/35724 Testing of Transmission line Protection and Control Equipment
D05/36350 Testing of Protection and Control Equipment – General Requirements
The following suits of drawings have been developed for the transmission line protection schemes:
Standard 110 kV Transmission Line Panel Design Index Sheet
Standard 220 kV Transmission Line Panel Design Index Sheet
Standard 220 kV Breaker and a Half Transmission Line Panel Design Index Sheet
Standard 220 kV Breaker and a Half Bus Coupler Panel Design Index Sheet
The following supporting documentation is relevant to transmission line protection:
Page 12 of 54
D06/48398 Electrical Protection Systems Key Performance Indicators
D09/73105 P&C Maintenance Strategy
D05/40065 System Spares Policy
D11/90909 Protection and Control Assets Risk Framework
D11/90038 Transend preparation for IEC61850
D12/10516 Transmission line protection replacement program Investment Evaluation Summary
D11/102320 Engineering and Asset Services operational expenditure planning methodology
D13/39576 Assessment of Proposed Regulatory Asset Lives - August 2013
2.2
Asset type
2.2.1
Protection schemes
Transend define a protection scheme as a group of devices used to detect all possible electrical
faults on a defined electrical circuit. The scheme may also provide fault clearance to adjacent or
downstream circuits as backup protection. In the case of transmission line protection, the devices at
each end of the transmission line, although working together to protect the same circuit, are counted
as individual protection schemes.
It is Transend’s policy to install duplicated protection devices known as main A and main B
protection on all transmission lines regardless of the National Electricity Rules (NER), clause
S5.1.9(d) for redundancy. All main protection devices are high speed and based on either current
differential or permissive under-reach distance principle. The high speed operation is required to
meet the fault clearance times of the NER.
A typical transmission line protection scheme comprises of:
a
main A transmission line protection;
b
main B transmission line protection;
c
back-up earth fault protection (integral with main A and main B protection devices in modern
protection schemes); and
d
bay controller and integrated bay RTU (modern schemes only).
2.2.1.1
Main A and B protection
Transend’s standard prescribes duplication of protection schemes designated as main A and Main B
protection devices. Main A and main B protection devices will not be of the same make and model
to prevent common mode failure.
All main protection devices are based on either a current differential or impedance (distance)
measurement principle or a combination of both. Current differential protection has the advantage
of higher speed operations and fault discrimination. Accelerated inter-tripping schemes are required
for distance protection to provide full transmission line coverage and to meet the NER fault
clearance times.
Page 13 of 54
2.2.1.2
Back-up protection
Back-up protection is provided by zone 2 and 3 distance protection and definite time earth fault
overcurrent protection. Typically, zone 2 has a time delay of 400 milliseconds and zone 3 has a time
delay of one second. Modern microprocessor devices provide the current differential protection and
the zone 2 and 3 distance protection as back up. They also enable a zone 1, instantaneous distance
protection element on the loss of differential protection communications facilities.
2.2.2
Technology types
The specific assets addressed in this asset management plan are protection devices installed over a
period of up to 57 years and can be differentiated from one another by three main technology types:
a
Electromechanical devices;
b
Static devices; and
c
Microprocessor devices.
2.2.2.1
Electromechanical
These were the first generation devices that operate via a mechanical force generated from the
interaction of an electro-magnetic field created by current and/or voltage signals. Transend has
several original 1960s commissioned protection devices installed on the transmission system.
Electromechanical devices are inherently simple in construction and operation, but are not able to
be self-supervised or provide disturbance and event recording facilities. As electromechanical,
being the forerunner of new generation protection devices, they have been subjected to operational
and environmental conditions during their service life to date. As a result the wear and tear and
degradation on components over time is likely to cause the devices to fail, be slower in operation or
drift in its operating characteristics.
2.2.2.2
Static
Static devices were developed and introduced to the transmission system in the 1960s. They have
minimal moving parts and employ electronic components to create protection characteristics. They,
like the electromechanical devices are not able to be self-supervised or provide disturbance and
event recording facilities. Transend has a significant number of static devices on the transmission
system which were installed in the 1970s to replace electromechanical overcurrent devices in
response to a number of major black-outs. Most static and electromechanical device types are no
longer supported by manufacturers, leading to a declining of the spares holdings required to
maintain these devices.
2.2.2.3
Microprocessor
Microprocessor based devices were developed in the 1980s. They operate by the conversion of
analogue signals to digital signals, which are then processed based on embedded firmware via a
microprocessor. With the increase in processing power, modern microprocessor devices have more
capability than earlier models. They are able to alarm for internal faults and provide additional fault
detection from multiple protection algorithms and functionality such as disturbance and event
recording, fault location and remote interrogation.
Page 14 of 54
2.2.3
Technology population
Table 1 and figure 2 represents the quantities of each type of technology installed on transmission
line protection schemes. Most 220 kV transmission line protection schemes are microprocessor
based due to the protection upgrade programmes undertaken over the past decade.
Older electromechanical and static installations often applied different devices for specific functions
such as phase fault, earth fault, disturbance recording, synchronising check and auto reclose. Newer
installations tend to have two multifunction microprocessor devices per transmission line protection
scheme.
Table 1
Transmission line protection device technology types per scheme
Scheme type
Technology
Electro Mechanical
Static
Microprocessor Total
110 kV transmission line
19
124
313
456
4
20
171
195
Total
23
144
484
651
Figure 2
Transmission line protection device technology types per scheme
350
300
250
200
Electro Mechanical
Static
150
Microprocessor
100
50
0
110kV Transmission Line
Figure 3 depicts the technology types distributed amongst Transend substations. Most notably are
Chapel Street, Farrell and New Norfolk substations containing large numbers of static technology
devices; this also highlights the number of devices required per scheme compared to equivalent
Page 15 of 54
microprocessor based schemes. Chapel Street Substation is planned for transmission line protection
upgrade in 2014; Farrell Substation is planned for transmission line protection upgrade in 2016; and
New Norfolk Substation is planned for transmission line protection upgrade in 2013.
Figure 3
Technology types per substation
Wesley Vale
Wayatinah Tee
Waddamana
Ulverstone
Tungatinah
Trevallyn
Temco
Tarraleah
Starwood
Smithton
Sheffield
Scottsdale
Rokeby
Risdon
Railton
Queenstown
Port Latta
Paloona Tee
Palmerston
Norwood
North Hobart
Electro Mechanical
New Norfolk
Microprocessor
Mowbray
Static
Mornington
Meadowbank
Lindisfarne
Liapootah
Knights Road
Kingston
Hadspen
Gordon
George Town
Farrell
Emu Bay
Electrona
Devonport
Derby
Creek Road
Chapel Street
Burnie
Bridgewater
Boyer
Avoca
0
2.3
10
20
30
40
50
60
Age profile
The age profile for transmission line protection devices is presented in figures 4 and 5. There are a
significant number of electromechanical and static devices in service which have now exceeded
Page 16 of 54
their expected service life. The service life for electromechanical protection devices is generally
accepted to be 40 years and static protection devices is generally accepted to be 20 years. Such a
determination is based on the expected design life of the devices mechanical and electronic
components, the decline in the availability of spares and manufacturer support, the reduced
performance levels and the increasing maintenance costs.
A number of these devices are exhibiting such symptoms, which provide strong drivers for their
replacement.
Progressively the non-compliant and problematic devices will be replaced with modern equivalents.
The shorter life expectancy of modern devices, which is expected to be predominately driven
through a lack of manufacturer support and price driven build quality, will require a continuous
cycle of asset replacements every 15-20 years.
The major areas for attention are the transmission line protection devices aged between 21 and 40
years. The majority of these devices are static devices, exceeding their life expectancy.
Figure 4
Transmission line protection device age profile
250
200
150
Electro Mechanical
Microprocessor
100
Static
50
0
0-5 yrs
6-10 yrs
11-15 yrs
16-20 yrs
21-25 yrs
26-30 yrs
31-35 yrs
36-40 yrs
>40 yrs
Page 17 of 54
Figure 5
Transmission line protection age profile per scheme type
160
140
120
100
80
60
40
20
0
2.3.1
0-5 yrs
6-10 yrs 11-15 yrs 16-20 yrs 21-25 yrs 26-30 yrs 31-35 yrs 36-40 yrs
>40 yrs
Economic life
The transmission line protection assets have an economic asset life of 15 years as defined by
Sinclair Knight Merz (SKM) in its ‘Assessment of Proposed Regulatory Asset Lives’ document
prepared in August 2013. Even though electromechanical devices have been allocated a physical
lifespan of 40 years and static devices 20 years, the depreciation period has been assigned as 15
years due to the fact that it is the protection scheme that is depreciated and not the individual
protection assets and it should be noted that a protection scheme may comprise of a combination of
microprocessor, static and electromechanical devices.
Over the past 10 years the following 34 substations have had transmission line protection schemes
installed or replaced:
•
Bridgewater
•
Knights Road
•
Risdon
•
Burnie
•
Liapootah
•
Rokeby
•
Chapel Street
•
Lindisfarne
•
Scottsdale
•
Creek Road
•
Mornington
•
Sheffield
•
Derby
•
Mowbray
•
Smithton
•
Devonport
•
New Norfolk
•
Temco
•
Electrona
•
Norwood
•
Trevallyn
•
Emu Bay
•
Palmerston
•
Ulverstone
•
Farrell
•
Paloona
•
Waddamana
•
George Town
•
Port Latta
•
Wesley Vale
•
Gordon
•
Queenstown
Page 18 of 54
•
Kingston
•
Railton
2.4
Scheme functionality
2.4.1
Main protection devices
Section 3.1 of the Protection of Transmission Lines Standard specifies the main functionality of the
transmission line protection devices as:
a
Capability to detect all faults on the transmission line including those on multi-ended
transmission lines;
b
Protection for all types of shunt faults;
c
Capability of detecting earth faults having a resistance of up to 100 ohms;
d
Switch On To Fault (SOTF) protection;
e
Fault location indication on the device and remotely through the SCADA system;
f
Phase segregated measurement and phase identification for the faulted phase;
g
Dynamic stabilisation against current transformer (CT) saturation;
h
Inter-tripping of remote breakers;
i
Three phase under voltage and over voltage protection;
j
Voltage transformer (VT) fuse failure protection with separate monitoring of individual
phases. The fuse failure protection shall block the operation of any voltage operated function
of the protection device;
k
Supervision of CT secondary, the output of which may be used to block the protection and to
provide an alarm;
l
Capable of communicating all parameters including the protection settings and recorded
events to the substation SCADA system and be capable of being configured remotely (via
substation SCADA or separate communications interface).
m
Inbuilt event and disturbance recording with time and date tagged events recorded and
displayed locally and remote.
n
Inbuilt distance protection capable of being independently switched into service permanently
or automatically upon failure of the differential communications or any of the associated
devices;
o
Three phase directional and non-directional over current and earth fault protection;
p
Circuit breaker failure (CBF) protection consisting of overcurrent check functions together
with timers adjustable from zero to 300 milliseconds;
q
Inbuilt ‘stub’ protection when applied to breaker and a half and double breaker
configurations; and
r
Trip circuit supervision (TCS) to monitor the associated trip circuit and circuit breaker trip
coil.
Page 19 of 54
2.4.2
Bay controller
Section 6.1 of the Protection of Transmission Lines Standard specifies the main functionality of the
bay controller as:
a
Single or multiple shot auto reclosing with freely configurable reclaim and dead time for each
reclose shot;
b
Monitoring busbar voltages and transmission line voltages;
c
Monitoring the status of the bay and other relevant disconnectors and to provide logic for the
interlocking scheme and for voltage selection for metering and protection applications;
d
The ability to be connected to the station SCADA system for alarms and monitoring and for
circuit breaker control; and
e
Settings to allow synchronism check before auto reclose following a three pole trip. The
synchronising check unit shall check for magnitude difference of voltage and frequency and
phase angle difference of voltage prior to allowing closure of the circuit breaker.
2.5
Makes and models
There is a wide variety of device makes and models installed across the transmission system
reflecting the fact that in past years there was no policy concerning standardisation of scheme
components. Transend is now actively seeking to standardise on a smaller number of device types
to reduce the overheads associated with maintaining a diverse range of equipment.
Transend have standardised on the Areva P543/P544 and the Schweitzer SEL311L models for the
protection of transmission lines and are utilising the Foxboro SCD5200 as the bay controller. These
devices comply with Transend standards having both current differential and distance protection
functions and are suitable for most protection scheme applications. The Foxboro SCD5200 bay
controller does not fully comply with the Transend standard as it is primarily a bay remote terminal
unit (RTU) but this is an interim arrangement until the next review of the standard 110 kV
transmission line protection scheme design is implemented.
2.5.1
Electromechanical devices
There are still a small number of electromechanical devices installed on Transend’s network, most
notably are the DPDL120 and DSF7 models of pilot wire differential protection installed at Rokeby,
Creek Road and North Hobart substations and the Rokeby transition structure. The devices at Creek
Road and North Hobart substations are all planned to be decommissioned by 2014 and all
electromechanical devices should be removed from the transmission line protection schemes by
2016. Figure 6 and 7 show the number and location of these devices in service.
Page 20 of 54
Figure 6
110 kV transmission line protection electromechanical devices
4
3.5
3
Avoca
Creek Road
2.5
Farrell
Knights Road
2
North Hobart
Palmerston
1.5
Paloona Tee
1
Rokeby
0.5
0
CDG
CTU
DPDL120
DSF7
LH1D
PBO
RXAP6300
RXAP6302
RXAP6322
The GEC CDG and Metropolitan Vickers PBO are both three phase overcurrent protection whilst
the English Electric CTU provides earth fault protection. The Compagne Des Compteurs DPDL120
and the GEC DSF7 are both pilot wire differential protection devices. The Brown Boveri LH1D and
the Compagne Des Compteurs RXAP models are distance protection devices.
Figure 7
220 kV transmission line protection electromechanical devices
4
3
2
George
Town
1
0
XF3-40
The Relays Pty Ltd XF3-40 device utilises pilot cables to transfer inter-trip signals across short
transmission lines. The devices are used only on the George Town – Comalco 220 kV transmission
lines which are 1.2km long.
2.5.2
Static devices
There is a range of static technology models installed on transmission line protection schemes and
mainly on 110 kV circuits. From the planned replacement program, the variation of static device
Page 21 of 54
models shall be reduced from 26 to one by the end of 2017. Figure 8 and 9 show the number and
location of these devices in service.
Figure 8
110 kV transmission line protection static devices
Avoca
20
18
16
Boyer
Burnie
Chapel Street
Creek Road
14
Farrell
12
George Town
10
Kingston
8
6
4
2
0
Knights Road
Meadowbank
New Norfolk
North Hobart
Palmerston
Paloona Tee
Risdon
Tarraleah
Tungatinah
The ABB RXIB24, Email 2C149K7 and GEC CTIG39 are all basic overcurrent devices used for
circuit breaker fail (CBF) protection. The GEC MCGG22, Schlumberger PSEL, PSWS and RSAS
and Asea RXPE47 and RXIG22 are all earth fault devices with the PSEL and PSWS providing
directionality. The Siemens 7SE121 is a dedicated fault locator. The Email 2SY110K18 is a
dedicated synchronism check device. The Schweitzer SEL-2505 and SEL-2506 and the Lenkurt
937B are all Teleprotection devices used for inter-tripping. The Reyrolle THR, GEC YTS and
PYTS, Schlumberger PDS2000B, Asea RAZOA and RAZOG, Brown Boveri LZ92 and Mitsubishi
MDT-B151 are all distance protection devices.
Page 22 of 54
Figure 9
220 kV transmission line protection static devices
5
4.5
4
3.5
Burnie
3
Farrell
George Town
2.5
Palmerston
2
Sheffield
1.5
Wayatinah Tee
1
0.5
0
DM695
MCGG22
MPC-SB201
QUADRAMHO
SEL-2505
SEL-2506
The only static devices installed on 220 kV transmission line protection schemes different to the
110 kV transmission line protection schemes are the GEC Quadramho distance protection device,
Dewar DM695 Teleprotection device and the Mitsubishi MPC-SB201 phase comparison device.
2.5.3
Microprocessor devices
Since 1995, Transend have been installing microprocessor devices on transmission line protection
schemes. At present, microprocessor devices represent the majority of devices across all schemes
with a variation of 36 models. Based on planned asset replacements and the standardisation
strategy, the variation of models should be reduced to 23 by the end of 2022. Figure 10 and 11 show
the number and location of these devices in service.
Page 23 of 54
Figure 10
110 kV transmission line protection microprocessor devices
70
Boyer
Bridgewater
60
Burnie
Chapel Street
50
Creek Road
Derby
40
Devonport
Electrona
30
Emu Bay
Farrell
20
George Town
Hadspen
Knights Road
10
Lindisfarne
Mornington
0
Mowbray
The Siemens 6MD665, GE Multilin C60, Areva C264 and ABB REC561 are all dedicated bay
controllers. The Foxboro SCD5200 is essentially a Remote Terminal Unit (RTU) but was
programmed to provide most of the bay controller functions in order to rationalise the number of
devices in the recent transmission line protection scheme design. The Siemens 7SA63 models are
primarily distance protection devices but operate as bay controllers with the distance protection
function enabled as back up protection and the Siemens 7SJ642 is primarily a feeder protection
device but is used as a bay controller on two particular schemes and as an auto reclose device on
four schemes.
The Siemens 7VK512 is a dedicated auto reclose device.
The Areva P122 and P821and Siemens 7SV600 are basic overcurrent device used for CBF
protection.
The Dewar DM1200 is a Teleprotection device used extensively throughout the network.
The ABB SPAU140C is used for synchronism check.
The Siemens 7SA522, GEC LFZP122, ABB REL316 and REL511 and Schweitzer SEL321 and
SEL421 models are used only as a distance protection device.
The Siemens 7SD511 and 7SD522 are dedicated current differential protection devices and the
Areva P543, Siemens 7SD523 and Schweitzer SEL-311L are current differential with distance
protection. The Areva P543 also provides the auto reclose functionality in the recent transmission
line protection scheme because the Foxboro SCD5200 is not easily programed to perform this
function.
Page 24 of 54
Figure 11
220 kV transmission line protection microprocessor devices
30
25
Burnie
Chapel Street
20
Farrell
George Town
Gordon
15
Hadspen
Liapootah
10
Lindisfarne
Palmerston
Sheffield
5
Waddamana
Wayatinah Tee
0
Devices used on the 220 kV transmission line protection schemes are similar to the 110 kV
transmission line protection schemes other than the ABB RCRA100 disturbance recorder and
RELZ100 distance protection device and the CSD Hathaway IMS8 disturbance recorder.
The Siemens 7SD512 differs from the 7SD511, the GEC LFZP111 differs from the LFZP122 and
the ABB REL521 differs from the REL511, all offering single phase tripping which is required for
single phase auto reclose of the 220 kV network.
The GE Multilin L90 multifunction device has been used recently for the circuit breaker and a half
switchyard re-configuration at George Town because the Schweitzer SEL-311L does not provide
multiple current inputs. Transend is aware that Schweitzer is planning to discontinue the production
of the SEL-311L multifunction device in which Transend will plan to implement the L90 as the new
standard main B transmission line protection device.
3
Condition monitoring practice
Protection devices that are in good condition can be expected to reliably operate (isolate circuits)
when they detect a fault. This action will prevent equipment damage and power system instability.
Practically, the only way to determine if a device is likely to operate when required is to perform a
test. These functional tests are crucial for protection device condition assessment or preventive
maintenance.
Deterioration of condition is of most concern with the older electromechanical and static devices in
service. Protection devices typically degrade in condition in the following ways:
a
Electromechanical devices tend to seize if not ‘exercised’ or trip contacts build up corrosion
leading to high resistance circuits. Periodical testing will detect the slower operating
performance or non-performance;
b
Static devices may suffer from the degradation of the materials in general and electrolytic
capacitors in particular. Periodical testing will detect if certain internal components may have
failed or calibration has drifted; and
Page 25 of 54
c
Newer microprocessor devices may exhibit quality issues relating to their hardware and
firmware implementation often giving rise to common failures across a batch. The ability of
the newer microprocessor devices to run self-diagnostic software help to detect failures before
protection mal-operation occurs during transmission system fault detection.
The condition of transmission line protection assets are assessed at regular intervals during periodic
maintenance (routine test) programs. In the case of modern microprocessor devices, condition
related issues are immediately alarmed by self-supervision functions through the SCADA system.
Transend’s policy for condition monitoring of secondary assets is to perform functional and
secondary injection testing based on the following criterion:
d
Devices with self-supervision are tested at six year intervals;
e
Devices without self-supervision are tested at three year intervals; and
f
Device that have been re-configured by either modification to settings/firmware or wiring are
tested at the time of modification.
Protection manufacturers recommend that devices with self-supervision do not require continued
injection testing following installation, accordingly the above policy is currently being reviewed.
The process of protection testing is to simulate real system fault conditions at the terminals of the
device and compare the devices output response to an expected response as a percentage of error.
Tolerance limits are set to determine whether the protection device is operating correctly.
Trending of the percentage error is not performed to determine the condition of the protection
device as it is generally accepted that calibration drift within the testing tolerances does not give an
accurate measure of device wear, whereas calibration drift outside of the testing tolerances does and
is recorded as a ‘defect’. Therefore the condition monitoring aspect of periodic protection testing is
the capture of device defects.
Similarly devices that have failed, usually found either during fault mal-operation or from selfsupervision alarms are also recorded as device defects providing condition monitoring information.
3.1
Defect management practices
Asset defects are recorded directly against the asset registered in the asset management information
system (WASP). The record captures the date of the defect in order to report the age of the device
when the defect occurred and categorised as either a ‘hardware failure’ or a ‘design error’. A
hardware failure is a failure that was a result of the manufacture or breakdown of the device and a
design error is the result of human action such as incorrect application of settings or poor
installation. Only hardware failure defects are used to determine the device condition and asset risk
reports as they provide information on the condition of the asset model rather than its
implementation. The secondary system asset risk methodology is discussed in more detail later in
this document.
3.2
Asset Condition Summary
The condition of transmission line protection assets are assessed at regular intervals during periodic
maintenance testing.
In the case of modern microprocessor devices condition related issues are immediately alarmed by
self-supervision functions through the SCADA system.
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The assets assessed with a poor condition are tabulated in Appendix A of this plan. The following
sub-sections details the high risk elements of the condition summaries.
3.2.1
Electromechanical
Over time all electromechanical devices degrade due to atmospheric conditions and aging which
eventuate into high resistance contact, sticky and sluggish moving parts and change in operating
characteristic due to loss of spring tension and magnetism.
The RXAP model of electromechanical device is of particular concern as they are a switched
electromechanical distance protection device comprising of a single measuring element. They have
been measured as slow in operation during periodic maintenance tests and have failed to initiate
circuit breaker auto reclose during fault clearance. These devices are physically large, requiring
three people to lift the device onto the protection panel, transportation of a spare would require a
utility vehicle and there is limited technical expertise in Tasmania to undertake the corrective
maintenance. Therefore, replacing a failed device with an identical spare is not practical and
corrective maintenance would involve installation of a different device resulting in higher corrective
maintenance costs.
Electromechanical devices do not have the functionality of modern numerical devices such as
disturbance recording, fault locating, and integrated SCADA functionality.
3.2.2
Static
There are a number of static device types in-service on the transmission system that are also
showing signs of condition degradation, typically requiring regular card replacements to sustain
their functionality. Spares are no longer available from the device suppliers hence it is important
that a program of replacements for these devices be sustained to provide spares.
The GEC CTIG39, Asea RXPE47 and Schlumberger PSEL3000 are all obsolete with no
manufacturer support. Transend do not have spares for these models and all devices are more than 5
years past their designed life expectancy.
Static devices do not have the benefits of modern microprocessor devices such as disturbance
recording, fault locating, self-monitoring and integrated SCADA functionality. With the lack of
self-supervision, periodic maintenance frequencies are double that of microprocessor devices and
the reliability of the devices is not guaranteed between periodic maintenance tests.
3.2.3
Microprocessor
The only microprocessor device installed on transmission line protection schemes that has been
assessed with a poor condition is the CSD Hathaway disturbance recorder. The poor condition of
this asset does not present a risk to the transmission circuit as this device is not used to initiate fault
clearance; rather it is used to capture event records during the fault clearance by the main protection
devices. This device has been assessed with a poor condition based on product obsolescence, the
lack of spares, difficulty to maintain due to little product familiarity and the lack of functionality as
modern devices incorporate the disturbance recording into the main protection devices.
Additionally, the GEC LFZP111 and LFZP122 and the ABB RELZ100 distance protection devices
have a medium condition rating due to obsolescence and lack of functionality.
A basic condition assessment has been carried out on all transmission line protection relays to
quantify the asset condition based on common factors. A health score has been formulated to
identify the assets of lower condition to include within the risk assessment during the investment
Page 27 of 54
evaluation process. Factors such as manufacturer support, spares availability, functionality and
maintenance complexity have been considered within the condition assessment.
Figure 12 depicts the condition of transmission line protection devices for the 110 kV and 220 kV
scheme specifications. The protection schemes assessed with a poor condition will be targeted for
replacement as a priority. There are more protection devices identified as poor condition on the
110 kV transmission lines. With the current and proposed replacement programs, all 136 devices
identified with poor condition should be replaced by 2018.
Figure 12
Transmission line protection devices condition summary
300
250
200
150
100
50
0
Poor
Medium
Good
3.3
Special operational and design issues
3.3.1
Operational issues
Transend’s recent protection schemes (as with the rest of the transmission system assets) are the
product of previous network management philosophies, system design assumptions and installation
practices that have evolved over time.
New performance criteria and changes in regulations bring about situations where protection
schemes that were acceptable in the past, are possibly no longer compliant with modern rules and
operating conditions. In some situations, protection schemes may remain in service until the first
opportunity to change the protection scheme.
Additionally, the availability of inter-substation communications bearers limits the performance and
redundancy requirements of the protection scheme. Over time communications bearers are installed
to address these identified deficiencies.
Page 28 of 54
A number of scheme shortcomings and system limitations have been identified from various system
studies (due to the above factors). Such transmission line protection limitations are as follows:
a
Knights Road–Electrona 110 kV transmission line
This transmission line cannot be operated normally closed due to issues with the distance protection
coordination in the area. It is planned to remove this restriction as part of the Huon area
augmentation project by installing duplicate unit protection on all of the effected circuits. This will
require a transmission line protection upgrade on all ends of the Chapel Street–Knights Road–
Kingston, the Chapel Street–Electrona–Kingston, and the Knights Road–Electrona transmission
lines, as well as installation of an optical fibre communications bearer to Knight Road Substation.
This project is presently underway.
b
Farrell–Que–Savage River–Hampshire–Burnie 110 kV transmission line
This transmission line normally runs with the B152 circuit breaker open at Hampshire; hence the
loads are radially supplied from Burnie and Farrell substations. The two distance protection
schemes at Burnie and Farrell are configured to be operated with the circuit breaker at Hampshire
closed; however, a transmission fault would then result in the complete loss of supply to
Hampshire, Savage River and Que substations. Due to the radial configuration of the transmission
line distance protection, signalling cannot be implemented between Burnie and Farrell substations
and fault clearance beyond the Que tee is slower than the requirements of the NER.
Options are being considered to reconfigure the transmission line and associated protection at these
substations enabling the line to be operated with the B152 circuit breaker permanently closed at
Hampshire. This is to be re-evaluated only if additional connections are required in the future.
c
The protection on this transmission line is inadequate due to there being only single current
differential protection devices installed at
For a failure of
the main protection devices or the associated communications circuit, fault clearance relies on the
The impact of this arrangement is the
back-up distance protection at
loss of generation at
for a transmission line fault on the
transmission line. An event of this nature happened in February 2007, when a
transmission line fault occurred due to a lightning strike concurrently with a disruption of the
microwave communications bearer. The fault was isolated at
resulting in the
This circuit is a connection asset with
loss of
As such the upgrade will need to be negotiated with the customer to be progressed. It is
proposed to seek advice from
regarding upgrading this scheme. Additional
communications bearers will be required and possibly a line VT at
Operating instructions state that the
transmission
lines must be taken out of service on the loss of the single protection communications. Additionally,
the impact of this slow fault clearance is the possible loss of synchronism of the
power stations for a
transmission line fault
during a communications failure.
3.3.2
Substation design issues
The transmission line protection schemes for the George Town–Comalco 220 kV transmission lines
4 and 5 are currently housed in the one panel. This presents a risk that a panel fire will affect both
schemes resulting in a double circuit outage. There is also a risk of an inadvertent fault due to
human intervention that can occur during a planned single circuit outage for maintenance which
could result in the in-service transmission line to trip. A double circuit outage on these circuits will
Page 29 of 54
result in a complete loss of supply to the
Depending on the duration of the
outage this will mean
could suffer a loss of production or permanent plant
damage.
The protection for these circuits was scheduled to be replaced in 2006 with individual circuit
cubicles. However these works were delayed due to early performance issues with the C264 bay
controllers. The replacement panels are installed and are waiting pre-commissioning. These
upgrades will be proceeding in the near future.
Modern protection scheme designs include enclosed panels for housing the devices. This design
aligns with the substation fire suppression strategy in which fine water mist is used to extinguish
early panel fires. This system will not work where protection devices are installed in open racks as
has been the case for protection scheme prior to 2002.
3.4
Asset compliance
Transmission line protection is required to meet the compliance requirements as contained in the
NER, which define that protection schemes must be designed and installed to meet minimum levels
of:
a
operating time;
b
redundancy;
c
backup protection;
d
auto re-close synchronisation facilities; and
e
impact on power system stability.
A number of the transmission line protection schemes do not meet the technical requirements of the
NER, but are covered by the grandfathering derogation until modified. When these schemes are
replaced they will need to meet prevailing NER standards which are more onerous than standards
that exist at the time of the original installation. In many cases this will involve investment in
additional communication bearers in order to install fully redundant future systems.
A number of transmission line protection schemes do not meet the technical requirements of the
NER, but are deemed to be compliant until the scheme is upgraded. These schemes are:
f
Tungatinah–Lake Echo–Waddamana 110 kV transmission line 1 and 2
The protection schemes on these transmission lines were found not to meet the redundancy
requirements of the NER due to the duplicated accelerated distance protection schemes utilising the
same communication bearers. The impact of this non-compliance is the possible loss of
synchronism at
power stations for a transmission fault during
a communications failure. It is proposed to upgrade the communications for this scheme by
installing a fibre optic link between
and the Liapootah–Palmerston
220 kV transmission line OPGW. The next major works planned for these circuits will be the redevelopment of Tungatinah Substation. It is proposed to incorporate the communications upgrade
as part of this project. It is proposed to bring these protection schemes to full NER compliance as
part of the Tungatinah Substation redevelopment project.
g
Meadowbank–New Norfolk 110 kV transmission line
The protection schemes on this transmission line were found not to meet the clearance time
requirements of the NER for a 3 phase fault due to there being no accelerated schemes installed.
The impact of this non-compliance is the potential loss of synchronism at
Page 30 of 54
for a transmission line fault. It is proposed to investigate the options for duplicate
communication bearers during the next scheduled protection replacement project for this circuit. It
is proposed to bring the protection scheme to full NER compliance as part of the Tungatinah
Substation redevelopment project.
h
Farrell–Rosebery–Queenstown 110 kV transmission line
This transmission line protection does not to meet the clearance time requirements of the NER due
to there being no accelerated schemes installed. The impact of this non-compliance is the possible
loss of synchronism at
for a transmission line fault. It is proposed to
install OPGW during the next scheduled protection replacement project for this transmission line
circuit. It is proposed to install a duplicated communication in time for the protection replacement
project at Farrell Substation.
i
transmission line
This transmission line protection does not meet the redundancy requirements of the NER. This is
due to the installation of a single accelerated protection scheme. The impact of this non-compliance
is the possible loss of synchronism of the
generators for a transmission
line fault during a communications failure. It is proposed to investigate the options of installing
to address the NER nonduplicate communications between
compliance.
4
Asset Performance
Performance levels of Transend’s transmission line protection population are assessed using a
combination of internal performance monitoring measures and external benchmarking.
4.1
Service obligations for prescribed assets
Transend’s performance incentive (PI) scheme, which is derived from the Australian Energy
Regulator’s (AER) Service Standards Guideline, is based on plant and supply availability. The PI
scheme includes the following specific measures:
a
b
plant availability:
i
transmission line critical circuit availability;
ii
transmission line non-critical circuit availability; and
iii
transformer circuit availability.
loss-of-supply event frequency index:
i
number of events in which loss of supply exceeds 0.1 system minutes; and
ii
number of events in which loss of supply exceeds 1.0 system minute.
Full details of the PI scheme and performance targets can be found in Transend’s TSMP.
Page 31 of 54
4.2
Service obligations for non-prescribed assets
4.2.1
Major Industrial customer connections
Transend have a number of direct connections to major industrial customers through transmission
lines. The following transmission line protection schemes are integral to those connections:
•
•
•
George Town-Comalco No.4 and No.5 220 kV transmission lines;
George Town-Temco No.1 and No.2 110 kV transmission lines; and
George Town-Starwood 110 kV transmission line.
The individual connection agreements describe the level of service and performance obligations
required from the associated connection assets.
4.2.2
Transend has a PI scheme in place with
under its Connection and Network Service
Agreement (CANS 2) for connection assets between the two companies. The PI scheme includes
PI scheme is described in more detail in the
connection asset availability. The
CANS 2 connection agreement.
4.2.3
Other generation sources
Transend also have direct connections to generation sources through transmission lines. The
following transmission line protection schemes are integral to those connections:
•
•
•
Studland Bay-Bluff Point-Smithton 110 kV transmission line protection at Smithton;
AETV-George Town 220 kV transmission line protection at George Town; and
George Town Converter-George Town 220 kV transmission line protection at George
Town.
The individual connection agreements describe the level of service and performance obligations
required from the associated connection assets.
4.3
Key Performance Indicators (KPI)
Transend monitors transmission line protection performance for major faults through its incident
reporting process. The process involves the creation of a fault incident record in the event of a
major transmission line protection failure that has an immediate impact on the transmission system.
The fault is then subjected to a detailed investigation that establishes the root cause of the failure
and recommends remedial strategies to reduce the likelihood of reoccurrence of the failure mode
within the transmission line protection population. Reference to individual fault investigation
reports can be found in Transend’s Reliability Incident Management System (RIMSys).
For transmission line protection failures that do not initiate a transmission system event, such as
minor failure or defects, Transend maintains a defects management system that enables internal
performance monitoring and trending of all transmission line protection related faults or defects.
4.3.1
Protection performance
Protection functions are required to operate in a secure and reliable manner to ensure that primary
system faults are isolated with the least disturbance to the rest of the network. Further, it is
Page 32 of 54
important that transmission line protection co-ordinates appropriately with downstream substation
protection schemes to optimise transmission system availability.
4.3.2
Disturbance recording
Accurate disturbance recording functions are required to ensure that system faults and device
operations can be reviewed to ensure systems are performing correctly.
4.3.3
Auto-reclose
The reliable performance of auto-reclose facilities is important to re-establish supply and maintain
network security in the event of transient transmission line faults.
4.3.4
Fault location
The ability to locate a transmission line fault is critical to enable the outage duration times and
associated costs to be kept to a minimum. Modern devices have integrated distance to fault
functions which can transmit an estimated distance to the fault from each end through the SCADA
system to the Network Control Centre.
4.3.5
Performance summary
The performance of protection assets relates to how well they perform against the original
specification and intended design functionality characteristics.
The performance monitoring system is being continually improved to better relate fault events to
specific assets. In addition, Transend has specified a set of protection assets key performance
indicators to better measure and manage protection performance within the Electrical Protection
Assets Key Performance Indicators document. Transend will continue to develop automated reports
for the performance of transmission line protection assets, monitoring the trends and effectiveness
of mitigating strategies.
4.3.5.1
Electromechanical devices
Older electromechanical protection devices have the tendency to be slow in operation when not
regularly exercised. This slow operation could result in a faulty transmission circuit not being
isolated within the timeframe as defined in the NER.
Such an example of this degraded performance was observed on three occasions between June 2004
and February 2005 when the RXAP6300 on the Knights Road-Kermandie 110 kV transmission line
operated slowly for a transient fault resulting in blocking of the auto reclose device and extended
outages to the Kermandie Substation. This device was tested as having an operate time of 100msec,
not including the circuit breaker opening time, whilst the NER allows a fault clearance time of
120msec on the 110 kV network.
4.3.5.2
Static devices
Static devices, may still be able to perform as intended in the short term, however the shortage of
spares will inevitably impact on static device protection performance. It is proposed to initiate an
incremental replacement program for static devices to mitigate the impact of spares unavailability.
An example of this was in February 2007 when the YTS distance protection device on the
Palmerston-Arthurs Lake 110 kV transmission line was found powered down during periodic
Page 33 of 54
maintenance testing. This was due to a failed power supply card and it was suspected to have been
in that condition for approximately 18 months. Spare cards were used to repair the failed device.
Additionally, in May 2009 the PDS2000B distance protection device on the Tungatinah-Butlers
Gorge-Derwent Bridge 110 kV transmission line was found powered down during periodic
maintenance testing. Again this was due to a failed power supply card and it is unknown how long
this device was in this condition.
4.3.5.3
Microprocessor devices
Minor technology integration issues associated with microprocessor devices have been far
outweighed by the benefits. Performance improvement is expected to become more evident as
electromechanical and static devices are replaced with microprocessor devices.
In most cases, defects found with some models of microprocessor devices are due to incorrect
application of settings. This can be attributed to the complexity of the device and unfamiliarity with
the model.
An example of this occurred in March 2006 when the 7SD511 current differential protection device
on the Bridgewater-Lindisfarne 110 kV transmission line operated for a fault on the WaddamanaBridgewater 110 kV transmission line. Post fault investigations revealed that the 7SD511 device on
the Bridgewater-Lindisfarne 110 kV transmission line had been set to look at current flow in the
reverse direction. During normal load current the protection scheme would have seen a small
amount of differential current but not enough to operate; with the higher current flow during the
fault on the adjacent transmission line, the differential current increased causing the protection
device to operate. This resulted in the total loss of load to Bridgewater Substation.
Modern microprocessor devices tend to mal-operate due to firmware failures. The maintenance of
firmware updates is difficult due to the requirements to download firmware, then software and then
testing to prove successful implementation. Prior to the firmware upgrade, there is generally a
period of communication and investigation involving the device manufacturer.
Examples of this were observed with the REL511 distance protection devices when between
November 2002 and November 2006 nine devices failed at various locations across the
transmission network. For each failure, the device was sent back to ABB for repair and following
investigations they identified a firmware bug that resulted in continuous writing to memory and
subsequent hardware failure. ABB issued a new firmware version that Transend maintenance
personnel applied to 16 devices.
4.4
Benchmarking
Transend participates in various formal benchmarking forums with the aim to benchmark asset
management practices against international and national transmission companies. Key
benchmarking forums include:
a.
International Transmission Operations & Maintenance Study (ITOMS); and
b.
Transmission survey, which provides information to the Electricity Supply Association of
Australia (esaa) for its annual Electricity Gas Australia report.
In addition, Transend works closely with transmission companies in other key industry forums,
such as CIGRE (International Council on Large Electric Systems), to compare asset management
practices and performance.
Page 34 of 54
4.4.1
ITOMS benchmarking
ITOMS provides a means to benchmark performance (maintenance cost & service levels) between
related utilities from around the world. The benchmarking exercise combines all Protection,
SCADA and communications assets into one distinct category. Further details relating to the
ITOMS studies are provided in ITOMS reports which are held by Transends Network Performance
and Strategy team.
In general, poor protection performance results from either mal-operation of older and less reliable
equipment prior to replacement, incorrect installation or human error during capital or maintenance
work.
Figure 13 illustrates Transend's benchmarked protection, SCADA and communications
performance against all other ITOMS participants for the last four reporting periods.
Figure 13
1
ITOMS Protection SCADA and communications benchmarked
performance chart1
The optimal performance location on the scatter plot is located in the upper right hand quadrant because, in this quadrant, service level is
at its highest at the least cost. The international benchmarked averages (cost & service) are shown as the centre crosshairs, with the
diamond shapes representative of surveyed participant utilities and regional averages shown as triangles marked NA (North America), EUR
(Europe), ASP (Australia South Pacific), and SCAN (Scandinavia).
Page 35 of 54
Figure 13 shows that from ’05 to ‘07 Transend recorded an increase in maintenance costs and an
increase in performance which can be attributed to:
a. Transend’s protection and control maintenance cycle resulted in a large proportion of
periodic maintenance scheduled during ITOMS 2007 period. Maintenance tasks have been
distributed more evenly for following years, reducing such peaks of intensive maintenance
from occurring.
b. Transends performance improvement in ’07 was mainly due to the replacement of older and
less reliable protection and control devices in ‘06 and the reduction of works undertaken as
a part of the ’03-’09 capital works program.
The trend shift from ’07 to ’09 shows that Transend recorded a continued increase in service
performance to be positioned better than the ITOMS international average, And a decrease in
maintenance costs which can be attributed to:
c. Maintenance services were in-sourced during 2008 by forming regional teams to perform
preventive, corrective and emergency response (call roster) activities at lower than contract
rates, this led to efficiency gains reducing operational and maintenance costs.
d. Ramping down of capital works during the end of ’04-’09 revenue period and improved
work practices through in-house maintenance services.
From ’09 to ‘11 Transend recorded a further decrease in maintenance costs to be positioned better
than the ITOMS international and Australia South Pacific (ASP) averages, and also recorded a
decrease in service performance which can be attributed to:
e. Regular replacement of older more maintenance intensive protection devices resulted in a
decrease in testing frequency and further efficiency gains derived through the in-sourcing of
maintenance services resulted in reduced costs.
f. An increase in Transend’s capital works program resulted in an increased exposure to
inadvertent protection operations. With multiple projects ensuing, project resources were
stretched leading to insufficient contractor supervision.
This AMP aims to ensure that the maintenance procedures and timeframes applicable to protection,
SCADA and communications have been reviewed and updated where needed to ensure that
Transend continues to provide acceptable system service levels whilst maintaining cost effective
maintenance and operation costs to continue providing positive benefits to our customers and
shareholders. Section 7 of this AMP contains the relevant opex and capex management plans to
ensure strong service levels and low maintenance spend continues to be delivered.
5
Risk
The risk assessment for transmission line protection schemes and devices has been approached from
a company-wide perspective (business risks) and will also be examined at the level of asset risk.
Page 36 of 54
5.1
Business risks
The following key business risks have been identified:
a
non-compliance – Transend has identified all NER non-compliant protection issues and
mitigation strategies as per the NER compliance assessment;
b
asset management – Transend has identified that foreseeable asset performance issues that
impact on the operation of the power system, property damage and/or loss of life is a major
risk to the business;
c
personnel constraints – Transend has acknowledged the resourcing constraints, both internal
and externally, to the electrical industry and developed and carried out a resourcing strategy to
address some of the issues associated with technical resources and appropriate competencies;
and
d
supplier support considerations – Transend acknowledges that equipment suppliers
generally provide spares and specialist support for their products only up to a limited time
beyond the design life of the equipment, and have therefore implemented a spares policy that
assists with maintaining protection assets beyond that provided by original equipment
manufacturers. In 2008 Transend audited the spares holding of non-obsolete protection
devices against the spares policy and procured $420,000 of spare protection devices to ensure
appropriate management beyond product obsolescence.
5.2
Asset risk
The risk of protection failure is usually qualified with statements like ‘failure of the protection
scheme will result in loss of supply to customers’ and ‘protection assets are required to minimise
damage to primary equipment’; however by quantifying the risk based on the condition of an asset,
a more accurate assessment can be achieved ensuring replacement programs target those assets that
are the highest risk to the transmission system. By calculating the risk in financial values, it is
possible to include risk in Net Present Value (NPV) analysis process and compare risk across
different asset classes.
In late 2010 Transend engaged EA Technologies to implement a condition based risk methodology
tool known as Condition Based Risk Management (CBRM). EA Technologies is a UK based
consultancy company with decades of asset management experience within the electricity industry;
however, they had never implemented P&C assets into their CBRM tool, or developed a
methodology for calculating asset risk for relays. Transend have developed a methodology that
aligns with the tacit knowledge of our P&C assets.
Risk includes a consequence, likelihood and a severity. Additionally, the risk is governed by the
type of failure of the P&C equipment.
5.2.1
Criteria for calculating asset risk
For a protection asset to initially qualify for the asset risk assessment it must first exceed either of
the most critical of condition criteria as follows:
a
Product obsolescence – The model of protection relay must be confirmed by the
manufacturer as obsolete or soon to be obsolete and no longer supported. This is a critical
trigger for asset replacement as it indicates that spares will start to deplete. As protection
relays age, the rate of failure increases. Normal operational maintenance practices will ensure
Page 37 of 54
a fast return of service; however, once dedicated spares are depleted, timeframes and costs to
return the service will increase.
b
Self-supervision – Since relay technology incorporated the microprocessor, the ability of a
relay to monitor its own health has proven a beneficial feature. This feature reduces the
operational expenditure as it is directly linked to Transend’s preventive maintenance policy
and it alleviates the risk of failure to operate because failure are known and relays are
replaced within eight hours after failure.
5.2.2
Consequence of protection failure
The consequence is expressed in dollars as these are tangible values. The consequences identified
for failure of a protection relay are:
a
Unserved energy – Unwarranted operation of a protection relay can result in the
disconnection of customer load. The amount of MW load disconnected for a period of time
gives a value of energy in MWh. To convert this into a financial value it is multiplied by the
Value of Customer Reliability (VCR) which accounts for all the financial impacts of
unplanned disconnection of customer load. Where redundancy is built into the primary circuit,
continuity of supply to customer loads will be maintained and the value of unserved energy
will be zero.
b
Contiguous unserved energy – Protection relay failure during a circuit fault requires the
operation of backup protection resulting in disconnection of upstream circuits. This causes
more load to be disconnected and results in a higher value of unserved energy. It is these
failures that have the highest impact on Transend customers.
c
Unplanned refurbishment – Once dedicated spares for a model of protection relays have
fully depleted, the cost to replace a failed protection relay with a different model of relay
includes:
i
procurement of a new replacement relay;
ii
re-design of the scheme circuitry and associated drawings;
iii
calculating new settings for the replacement relay; and
iv
installation of the new relay and re-wiring of the scheme circuitry.
5.2.3
Intangible consequences
Primarily, protection relays are required for the disconnection of faulted primary equipment to
maintain power system stability, but in addition, protection may minimize damage to primary
equipment, chances of bush fire start or human death from contact with live equipment. However,
these consequences are difficult to justify given that protection systems are designed with backup
and although backup fault clearance times are longer, there is no evidence to substantiate that
protection failure will increase the consequence. For this reason, the consequence of primary
equipment damage, bush fire start and human fatality are not considered as a risk of protection relay
failure.
5.2.4
Likelihood
The likelihood of a protection relay failure is derived from failure records and the expected end of
life. The likelihood is expressed as a percentage and known as the ‘failure characteristic’.
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a
Failure characteristic – The failure characteristic is a basic exponential characteristic
representing the number of relay failures per year per relay of the model. This exponential
increase is sometimes referred to as the ‘wear-out’ portion of the ‘Bathtub Curve’. The
characteristic is determined by setting a starting rate of failure and an ending rate of failure
and plotting an exponentially increasing rate of change between those two points.
b
Starting percentage of failure - The starting rate of failure is based on the average number
of failures per year of the model over the last three years per relay.
c
Ending percentage of failure – The expected design life of a microprocessor relay is 15
years, a static relay is 20 years and an electro mechanical relay is 40 years. The end of life
occurs when the ending rate of failure is deemed as 100 per cent failure of the model and is
set to occur at twice the design life of the asset.
5.2.5
Severity
The severity of the failure is dictated by a number of factors which are multiplied together when
they have an effect on the same consequence. The severity factors are as follows:
a
Spares depletion date – The spares depletion date triggers the start of the risk of unplanned
refurbishment. The predicted date that spares will have depleted is dependent on the date the
manufacturer ceases to supply replacements of and repair services for the model of relay, the
number of spares being held in stock and the failure characteristic. From the date that the
support services cease the spare stock begins to deplete at the predicted rate of failure until
such time as the spare stock reaches zero.
b
Redundancy – Redundancy or duplication in a protection scheme allows a single relay to fail
without depleting the schemes ability to clear a fault on the primary circuit. Redundancy in a
protection scheme alleviates the risk of contiguous unserved energy.
c
Self-supervision – Self-supervised equipment monitors the health of its internal operation
such as the power supply, digital processing and memory capacity. Some modern relays even
monitor the health of output contacts. When a self-supervised protection relay fails it alarms,
initiating immediate corrective maintenance. The self-supervision function alleviates the risk
of contiguous unserved energy.
d
Primary circuit’s exposure to faults – This risk is relevant only if the protection equipment
fails to operate at the instance of a fault on the primary system. Some primary circuits may
not be as exposed to natural faults, such as lightning or wind-blown vegetation. Transformers
are not as affected by wind storms as HV feeders are, hence this is a factor in the consequence
of protection failure. The severity of primary fault occurrence is used in the risk of contiguous
unserved energy.
5.2.6
Failure type
Relays can and have been observed to fail in two ways due to degradation of the hardware or
firmware components. Failures due to human intervention, such as incorrect settings or ‘finger
faults’ are not included in the calculation of protection induced risk as the intent of determining the
risk is to predict the end of useful life of the asset.
Relays usually fail where it does not operate when intended and usually occurs due to failure of the
internal power supply, a component or by seizure of moving parts. This type of failure has an effect
on risks such as unplanned refurbishment, non-compliance with the NER, human fatality,
Page 39 of 54
contiguous unserved energy and primary equipment damage. Failure to operate when required is the
most common type of failure and is given an 80 per cent rate of occurrence.
The other type of failure observed in relays is operation when not required either without a system
fault present or operating for a fault outside of the area it is protecting. This type of failure due to
equipment degradation is less common and given a 20 per cent rate of occurrence. These false
operations usually occur due to failure of internal components that are used to set the operate limits
such as spring tensions in electromechanical relays, leaks in electrolytic capacitors or poor solder
joints in static protection relays, loose connection in potentiometers associated with the timers or a
firmware ‘bug’ in a microprocessor relay. This type of failure effects risks such as unserved energy,
unplanned refurbishment and non-compliance with the NER.
5.3
Risk analysis and mitigating strategies
The condition analysis shown in the above mentioned appendices can be used to highlight the
suspected probability of failure and underlying risk. The mitigating strategies to reduce or eliminate
the identified risk, taking into account the probability of the risk and the possible impact is to
replace whole protection schemes with modern, cost effective and standardised equipment. Where
individual devices are identified as high risk and require immediate replacement, this shall be
undertaken as a one off individual device replacement project. An example of this strategy being
implemented was the replacement of the RXAP6300 device on the Knights Road-Kermandie
110 kV transmission line following the events mentioned in the performance summary of this asset
management plan.
For the business risks identified above, the following mitigating strategies shall be followed:
a
non-compliance – maintain a Protection Compliance Plan. Studies are conducted by
Transend’s Transmission Operations Group following changes in the transmission network.
The NER compliance status is to be used within the asset risk methodology to drive asset
replacement and augmentation programs;
b
asset management –maintain good asset records, asset management plans and technical
standards ensuring that policies such as standardisation and spare holdings are followed
throughout the business and by Transend’s contractors. Development of standard designs will
lock in equipment models ensuring alignment with the strategy to minimise the diverse range
of device models;
c
personnel constraints – investigate the option of performing periodic maintenance testing
less frequently on self-supervised protection devices, thus freeing up skilled resources to
perform more of an asset acceptance role ensuring higher quality installations of protection
schemes; and
d
supplier support considerations – standardise on acceptable protection devices ensuring that
manufacturer support is an important factor in product selection.
5.4
Monitoring and review
Whilst periodic testing provides one indication of protection performance, the actual performance
under fault conditions also provides a valuable indication of protection integrity. Of course these
events cannot be a substitute for periodic testing since some protection will not be subjected to
system faults and indeed some protection may never be called upon in its lifetime to operate for a
fault. However, the non-operation of protection not directly involved in a particular fault may
provide an indication that, in at least some aspects, the protection is functioning correctly. For these
Page 40 of 54
reasons, a comprehensive analysis of protection operation under fault conditions is always carried
out and also to determine if further field testing is required. The fault data captured by modern
protection schemes also provides an indication of protection performance under fault conditions.
6
Demand analysis
6.1
Planned augmentation
Transend’s requirements for developing the transmission system are principally driven by five
elements:
a
Load forecasts;
b
New customer connections;
c
New generation projects;
d
System security criteria; and
e
NER compliance.
Details of planned network augmentation works can be found in Transend’s ‘Annual Planning
Report’, which is updated on an annual basis.
6.2
Asset specific implications
Proposed network augmentation projects identified in the ‘Annual Planning Report’ will include the
installation of appropriate protection and control assets. This will increase the number of protection
and control assets within the network, resulting in higher operational and maintenance costs.
7
Lifecycle management plan
7.1
Issues summary
The major issues identified in the review of transmission line protection schemes are:
a
the management of standard transmission line protection scheme designs to increase asset
performance and lower operating and training costs;
b
to continue to develop a condition based risk methodology to provide improved replacement
programming;
c
the need to review transmission line protection scheme settings to ensure compatibility and
correct co-ordination with other protection assets;
d
to continue fault analysis and develop automated reports to determine asset specific and
system performance;
e
to continue rigorous management of microprocessor device firmware issues;
f
to continue the review of fault locating facilities to ensure that these assets are performing as
required; and
Page 41 of 54
g
the need to consider the implementation of IEC61850 into transmission line protection
schemes.
7.2
Maintenance plan
The performance of transmission line protection schemes is sustained by preventive maintenance
testing and corrective maintenance activities. All protection devices in Transend substations are
periodically tested to ensure that they are performing correctly as designed.
7.2.1
Preventive maintenance
Each protection scheme is tested to determine the health of the devices and corrective maintenance
work resulting from the tests is performed when identified. The policy for periodical maintenance
testing is based on the following:
a
self-supervised devices are to be tested at six yearly intervals; and
b
non self-supervised devices to be tested at three yearly intervals.
At present, Transend is investigating the option of minimising the testing regimes for selfsupervised devices as advised by protection device manufacturers. This strategy may involve the reallocation of maintenance resources to perform testing and asset acceptance of new installations.
The outcomes of this strategy may be reduced maintenance costs, minimised human error faults and
more efficient use of maintenance resources. This strategy is yet to be finalised.
7.2.2
Corrective maintenance
Corrective maintenance of transmission line protection assets is initiated by either:
a
device defects found during periodical maintenance testing;
b
device defects alarmed by self-supervision through the SCADA system;
c
device defects found during fault analysis of system occurrences; and/or
d
critical device firmware upgrades.
7.2.3
Technical support
Other operational costs which are not able to be classified under the above categories are allocated
to technical support. These tasks include:
a
system fault analysis and investigation;
b
area based setting coordination reviews;
c
preparation of asset management plans;
d
standards management;
e
management of the service providers;
f
training; and
g
general technical advice.
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7.3
Capital plan
Transend's transmission line protection capital investment strategy has been developed taking into
consideration the design related issues, condition, performance issues and risks associated with the
population of assets.
7.3.1
Scheme replacement strategies
The majority of transmission line protection scheme replacements are coordinated with substation
primary asset replacement projects; however, the asset life for primary equipment is generally 50
years whilst the asset life for protection schemes is generally 20 years leading to the majority of
future asset replacement projects being protection scheme replacements. To optimise on capital
project mobilisation, design and contracting costs, substation specific protection scheme
replacement programmes shall be developed.
Recent discussion within Transend is to develop a strategy for protection asset replacements
involving single device replacement rather than replacing the whole protection panel. This would
target only identified high risk protection devices for replacement and the acceptable lower risk
assets to remain in service for longer periods of time. The benefits of this strategy would include:
a
easier justification of replacement programs leading to a faster reduction in identified business
risks;
b
retention of protection scheme panels leading to better use of substation control building real
estate and re-use of secondary cables;
c
shorter equipment installation periods;
d
possible in-service protection replacement; and
e
less design and drafting requirements.
All of the above benefits would ultimately result in lower capital project costs.
At present the strategy is to house the protection devices in enclosed panels to minimise the risk of
damage from rodents, to assist with work area delineation during protection maintenance and to
align with the proposed substation fire suppression strategy.
Additionally, future plans are being considered to implement the IEC 61850 communication
standard at a station bus level within Transend substations. In order to maximise the full effect of
implementing IEC 61850 designs, protection, control and SCADA systems should be replaced
concurrently. The strategy for implementing the IEC 61850 standard is described in more detail in
the Transend preparation for IEC 61850 document.
The replacement of the transmission line protection associated with a substation bay will most
likely also impact on the protection arrangements at the remote end of the transmission line. The
extent of work required to the protection scheme at the remote end of a transmission line depends
on the type of protection schemes employed. Distance protection schemes will require
modifications to inter-tripping equipment, whereas current differential schemes will require the
replacement of the device so they match at both ends. For this reason it is often cost effective to
replace the protection schemes at both ends of the transmission line at the same time. It is likely that
this will not be achievable in all instances due to the need to also align with primary substation
redevelopments.
A combination of the above strategies will eventuate into the best option for protection asset
replacements.
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7.3.2
Scheme replacement program
To address the design, condition and performance risks associated with the transmission line
protection population, protection schemes highlighted in this asset management plan will be
programed for capital replacement.
As previously mentioned, where appropriate, the scope of each project will be integrated with the
replacement of the primary assets. Table 2 outlines the planned transmission line protection scheme
replacements for the period 2012 to 2022. Note that this information needs to be reviewed after
project prioritisation and this table does not include augmentation works.
Table 2
Transmission line protection replacement program
Locations
Type
Scheme
Schemes / Year
12-14
14-19
19-22
Avoca
110 kV
B1
1
Boyer
110 kV
A1, B1
2
Bridgewater
110 kV
G1, H1
Burnie
110 kV
E1, K1
Burnie
220 kV
A1
Chapel Street
110 kV
D1, F1, G1, H1
4
Creek Road
110 kV
B1, D1, E1, K1, L1, M1
6
Farrell
110 kV
P1, S1, T1 and N1
3
Farrell
220 kV
A1, B1
George Town
110 kV
T1
1
George Town
220 kV
B1, C1, D1, F1, G1 and Z1
5
Hadspen
110 kV
E1, G1, H1, J1, K1, N1
6
Hadspen
220 kV
P1, Q1, T1, V1
4
Kingston
110 kV
A1, B1
2
Knights Road
110 kV
A1, C1, J1
3
Liapootah
220 kV
E1 (Single device only)
Meadowbank
110 kV
A1, B1
2
New Norfolk
110 kV
D1, E1, F1, J1, K1, P1, R1
7
North Hobart
110 kV
A4, B4
2
Norwood
110 kV
A1, B1
Palmerston
110 kV
O1, R1, Y1, Z1
Palmerston
220 kV
B1, C1, D1, F1 and K1, L1
4
Paloona Tee
110 kV
B1 (Removal due to switchyard re-arrangement)
1
2
2
1
1
2
1
1
2
4
2
Page 44 of 54
Rokeby
110 kV
A1, B1 (Cable protection only)
2
Sheffield
220 kV
L1 and F1, J1
1
Tarraleah
110 kV
B1, C1, D1, E1, F1
5
Trevallyn
110 kV
B1, C1
Tungatinah
110 kV
B1, C1, D1, E1, F1
Wayatinah
220 kV
A1, B1
7.3.3
2
5
2
57
Totals
2
14
19
Standard scheme development
It is proposed to further develop the existing standard panel designs for 110 kV and 220 kV
transmission line protection schemes to include protection setting guidance, test procedures, signal
lists and operation notes.
It is proposed to review this standard transmission line panel every five years to ensure that
Transend realises the benefits offered by new technologies. To ensure that changes to panel designs
are fully tested and operationally complete, the review and re-design shall be coordinated with a
capital project by issuing a preliminary design to the capital project contractor prior to the
transmission line protection scheme installation. This strategy will ensure that new designs are fully
factory and site acceptance tested prior to being signed off as the new standard design.
7.3.4
Standardisation
The standardisation of protection and control schemes has become good industry practice by
Australian TNSPs. Standardisation reduces the resources required to design, review, and
commission protection and control schemes. It presents operational savings due to a higher degree
of commonality hence resulting in lower asset management and training costs. It is seen as the most
cost efficient method to deliver the number of protection replacement projects required in the
coming years. It also reduces the risk of human errors when testing the schemes on commissioning.
Transend’s experience in protection scheme standardisation has been the development of 110 kV
and 220 kV transmission line protection panels since 2004 and the creation of a 220 kV circuit
breaker and a half transmission line protection panel design in 2011.
The existing standard transmission line protection panel design is defined by a set of engineering
drawings. These drawings standardise the panel layout, internal wiring, external cabling, labelling,
and most importantly individual device inputs and outputs.
Much of the scheme design is undertaken in software, via the setting and configuration of the
devices and between devices via communication protocols. To achieve all the benefits of
standardisation it is proposed to extend the standard design to include protection setting guidance,
standard device configurations and standard signal lists.
It is also proposed to standardise on the commissioning plans and maintenance practices for each
standard scheme. This is expected to minimise the number of inadvertent failures due to incorrect
commissioning and maintenance protocols being employed by technical resources. These standard
test plans will then also be available for preventive and corrective maintenance tasks, supporting the
in-service devices throughout the entirety of their asset life. Operator guidance notes will also be
Page 45 of 54
developed to assist in the training of field staff, ensuring that they are able to interrogate devices
following system outages.
7.4
Disposal plan
Replaced transmission line protection devices are de-commissioned and removed from substations
as part of capital replacement projects. Required assets are retained for system spares, whilst all
other devices are offered to educational institutions and other relevant bodies for training purposes.
Devices which are no longer wanted or required will be disposed of by the Contractor.
8
Financial Summary
8.1
Operational expenditure
Budgets for operational expenditure are derived from preventive and corrective maintenance and
technical support estimates. These budgetary figures are prepared by the Engineering and Asset
Services teams for the operational activities on the entire population of assets as described in the
Engineering and Asset Services operational expenditure planning methodology document. To
derive the operational expenditure for the transmission line protection asset population, calculations
are prepared by the Network Performance and Strategy team to allocate a portion of the budget to
the transmission line protection asset population. The preventive maintenance budget estimates are
prepared from unit rates and planned maintenance schedules hence these values are precise. The
corrective and technical support budget estimates are based on previous expenditure trends and
expected changes to work practices.
8.2
Capital expenditure
For the development of Transend’s revenue proposal, capital expenditure for the proposed
transmission line protection asset replacement program is estimated as a level 1 by the Project
Services team.
Closer to the project initiation phase, the projects are more accurately estimated by the Project
Services team as a level 3A and are compared and consolidated with the project Contractor’s
submission to create a level 3B estimate which is included in the business case for expenditure
approval.
8.3
Investment evaluation
For each program or project to be included within Transend’s revenue proposal, an Investment
Evaluation Summary document is prepared describing the condition, performance, risk, options and
strategies identified within this asset management plan and an NPV summary for each identified
option is also presented to support the need for capital expenditure.
The Investment Evaluation Summary for this asset management plan’s proposed capital program is
D12/10516.
Page 46 of 54
9
Appendix A – Poor condition transmission line protection devices
Location
Scheme
Device ID
Device Description
Technology
Model
Manufactured
Age
Average
Defect Age
Support
Spares
Maintenance
Functionality
Health
Score
Avoca
AV-SCTC-B1
AV-B121A
Main A protection
Static
THR
1984
28
20
Low
Yes
Medium
Low
10.84
Avoca
AV-SCTC-B1
AV-B164
Earth Fault Protection
Electro Mechanical
CTU
1984
28
40
Low
Yes
Medium
Low
9.42
Avoca
AV-SCTC-B1
AV-B121B
Main B protection
Electro Mechanical
RXAP6322
1964
48
40
Low
No
Extreme
Low
18.42
Burnie
BU-SCTC-E1
BU-E121A
Main A protection
Static
PDS2000B
1977
35
20
Low
Yes
Medium
Low
11.54
Burnie
BU-SCTC-E1
BU-E121B
Main B protection
Static
PYTS101
1979
33
20
Low
Yes
Medium
Low
11.34
Burnie
BU-SCTC-E1
BU-E164
Static
PSWS190
1979
33
20
Low
Yes
Medium
Low
11.34
Burnie
BU-SCTC-K1
BU-K121B
Main B protection
Static
PYTS101
1979
33
20
Low
Yes
Medium
Low
11.34
Burnie
BU-SCTC-K1
BU-K164
Static
PSWS190
1979
33
20
Low
Yes
Medium
Low
11.34
Burnie
BU-SCTC-K1
BU-K121A
Main A protection
Static
PDS2000B
1977
35
20
Low
Yes
Medium
Low
11.54
Boyer
BY-SCTC-A1
BY-ADIT
Teleprotection
Static
937B
1978
34
20
Low
Yes
Extreme
Medium
11.44
Boyer
BY-SCTC-B1
BY-BDIT
Teleprotection
Static
937B
1978
34
20
Low
Yes
Extreme
Medium
11.44
Creek Road
CR-SCTC-B1
CR-B121A
Main A protection
Static
THR
1981
31
20
Low
Yes
Medium
Low
11.14
Creek Road
CR-SCTC-B1
CR-B164
Static
PSWS190
1981
31
20
Low
Yes
Medium
Low
11.14
Creek Road
CR-SCTC-B1
CR-B121B
Main B protection
Static
YTS
1977
35
20
Low
Yes
Medium
Low
11.54
Creek Road
CR-SCTC-D1
CR-D121
Main B protection
Static
YTS
1977
35
20
Low
Yes
Medium
Low
11.54
Creek Road
CR-SCTC-E1
CR-E121
Main B protection
Static
YTS
1977
35
20
Low
Yes
Medium
Low
11.54
Page 47 of 54
Location
Scheme
Device ID
Device Description
Technology
Model
Manufactured
Age
Average
Defect Age
Support
Spares
Maintenance
Functionality
Health
Score
Creek Road
CR-SCTC-K1
CR-K121
Main B protection
Static
YTS
1977
35
20
Low
Yes
Medium
Low
11.54
Creek Road
CR-SCTC-L1
CR-L151
Overcurrent Protection
Electro Mechanical
PBO
1955
57
40
Low
Yes
Medium
Low
10.87
Creek Road
CR-SCTC-L1
CR-L121
Main B protection
Static
YTS
1977
35
20
Low
Yes
Medium
Low
11.54
Creek Road
CR-SCTC-L1
CR-L187
Main A protection
Electro Mechanical
DSF7
1976
36
40
Low
Yes
Extreme
Low
11.82
Creek Road
CR-SCTC-M1
CR-M187
Main A protection
Electro Mechanical
DSF7
1976
36
40
Low
Yes
Extreme
Low
11.82
Creek Road
CR-SCTC-M1
CR-M121
Main B protection
Static
YTS
1977
35
20
Low
Yes
Medium
Low
11.54
Creek Road
CR-SCTC-M1
CR-M151
Electro Mechanical
PBO
1955
57
40
Low
Yes
Medium
Low
10.87
Chapel Street
CS-SCTC-D1
CS-D121A
Main A protection
Static
PYTS101
1979
33
20
Low
Yes
Medium
Low
11.34
Chapel Street
CS-SCTC-D1
CS-D121B
Main B protection
Static
PDS2000B
1979
33
20
Low
Yes
Medium
Low
11.34
Chapel Street
CS-SCTC-D1
CS-D164
Static
PSWS190
1979
33
20
Low
Yes
Medium
Low
11.34
Chapel Street
CS-SCTC-F1
CS-F121A
Main A protection
Static
YTS
1977
35
20
Low
Yes
Medium
Low
11.54
Chapel Street
CS-SCTC-F1
CS-F121B
Main B protection
Static
PDS2000B
1979
33
20
Low
Yes
Medium
Low
11.34
Chapel Street
CS-SCTC-F1
CS-F164
Static
PSWS190
1979
33
20
Low
Yes
Medium
Low
11.34
Chapel Street
CS-SCTC-G1
CS-G121
Main B protection
Static
YTS
1979
33
20
Low
Yes
Medium
Low
11.34
Chapel Street
CS-SCTC-H1
CS-H121
Main B protection
Static
RAZOG
1976
36
20
Low
Yes
High
Low
12.64
Farrell
FA-SCTC-A1
FA-A164
Static
MCGG22
1992
20
20
High
Yes
Medium
Low
8.04
Farrell
FA-SCTC-A1
FA-A121B
Main B protection
Static
QUADRAMHO
1993
19
20
Medium
Yes
Medium
Low
8.94
Farrell
FA-SCTC-A1
FA-A185A
Teleprotection
Static
DM695
1993
19
20
Medium
Yes
Extreme
Medium
8.94
Page 48 of 54
Location
Scheme
Device ID
Device Description
Technology
Model
Manufactured
Age
Average
Defect Age
Support
Spares
Maintenance
Functionality
Health
Score
Farrell
FA-SCTC-A1
FA-A185B
Teleprotection
Static
DM695
1993
19
20
Medium
Yes
Extreme
Medium
8.94
Farrell
FA-SCTC-B1
FA-B121B
Main B protection
Static
QUADRAMHO
1990
22
20
Medium
Yes
Medium
Low
9.24
Farrell
FA-SCTC-B1
FA-B164
Static
MCGG22
1991
21
20
High
Yes
Medium
Low
8.14
Farrell
FA-SCTC-N1
FA-N164
Static
PSWS190
1981
31
20
Low
Yes
Medium
Low
11.14
Farrell
FA-SCTC-N1
FA-N121A
Main A protection
Static
MDT-B151
1982
30
20
Low
Yes
Medium
Low
11.04
Farrell
FA-SCTC-N1
FA-N121B
Main B protection
Static
THR
1982
30
20
Low
Yes
Medium
Low
11.04
Farrell
FA-SCTC-N1
FA-NFL
Fault Locator
Static
7SE121
1982
30
20
Low
Yes
Medium
Medium
9.04
Farrell
FA-SCTC-P1
FA-P121B
Main B protection
Static
THR
1981
31
20
Low
Yes
Medium
Low
11.14
Farrell
FA-SCTC-P1
FA-P164
Static
PSWS190
1981
31
20
Low
Yes
Medium
Low
11.14
Farrell
FA-SCTC-S1
FA-S164
Electro Mechanical
CTU
1980
32
40
Low
Yes
Medium
Low
9.62
Farrell
FA-SCTC-S1
FA-S121A
Main A protection
Static
MDT-B151
1982
30
20
Low
Yes
Medium
Low
11.04
Farrell
FA-SCTC-S1
FA-S121B
Main B protection
Static
THR
1982
30
20
Low
Yes
Medium
Low
11.04
Farrell
FA-SCTC-T1
FA-T121B
Main B protection
Static
THR
1982
30
20
Low
Yes
Medium
Low
11.04
Farrell
FA-SCTC-T1
FA-T121A
Main A protection
Static
MDT-B151
1981
31
20
Low
Yes
Medium
Low
11.14
Farrell
FA-SCTC-T1
FA-T164
Static
PSWS190
1981
31
20
Low
Yes
Medium
Low
11.14
Farrell
FA-SCTC-T1
FA-TFL
Fault Locator
Static
7SE121
1986
26
20
Low
Yes
Medium
Medium
8.64
George Town
GT-SCTC-B1
GT-B185
Main A protection
Static
MPC-SB201
1984
28
20
Low
Yes
Extreme
Low
12.84
George Town
GT-SCTC-B1
GT-B121
Main B protection
Static
QUADRAMHO
1987
25
20
Medium
Yes
Medium
Low
9.54
Page 49 of 54
Location
Scheme
Device ID
Device Description
Technology
Model
Manufactured
Age
Average
Defect Age
Support
Spares
Maintenance
Functionality
Health
Score
George Town
GT-SCTC-F1
GT-F185A
Teleprotection
Electro Mechanical
XF3-40
1967
45
40
Low
No
High
Medium
15.27
George Town
GT-SCTC-F1
GT-F185B
Teleprotection
Electro Mechanical
XF3-40
1967
45
40
Low
No
High
Medium
15.27
George Town
GT-SCTC-G1
GT-G185A
Teleprotection
Electro Mechanical
XF3-40
1970
42
40
Low
No
High
Medium
15.12
George Town
GT-SCTC-G1
GT-G185B
Teleprotection
Electro Mechanical
XF3-40
1970
42
40
Low
No
High
Medium
15.12
George Town
GT-SCTC-T1
GT-T151CH
CB Fail Protection
Static
RXIB24
1970
42
20
Low
Yes
Medium
Low
12.24
Kingston
KI-SCTC-A1
KI-A121A
Main A protection
Static
PYTS101
1979
33
20
Low
Yes
Medium
Low
11.34
Kingston
KI-SCTC-A1
KI-A151CH
CB Fail Protection
Static
2C149K7
1979
33
20
Low
Yes
Medium
Low
11.34
Kingston
KI-SCTC-A1
KI-A164
Static
PSWS190
1979
33
20
Low
Yes
Medium
Low
11.34
Kingston
KI-SCTC-A1
KI-A121B
Main B protection
Static
PDS2000B
1977
35
20
Low
Yes
Medium
Low
11.54
Kingston
KI-SCTC-B1
KI-B121A
Main A protection
Static
PYTS101
1979
33
20
Low
Yes
Medium
Low
11.34
Kingston
KI-SCTC-B1
KI-B121B
Main B protection
Static
PDS2000B
1979
33
20
Low
Yes
Medium
Low
11.34
Kingston
KI-SCTC-B1
KI-B151CH
CB Fail Protection
Static
2C149K7
1979
33
20
Low
Yes
Medium
Low
11.34
Kingston
KI-SCTC-B1
KI-B164
Static
PSWS190
1979
33
20
Low
Yes
Medium
Low
11.34
Knights Road
KR-SCTC-A1
KR-A164
Static
RXPE47
1980
32
20
Medium
No
Medium
Low
16.24
Knights Road
KR-SCTC-A1
KR-A121
Main A protection
Electro Mechanical
RXAP6300
1963
49
40
Low
No
Extreme
Low
18.47
Knights Road
KR-SCTC-C1
KR-C151
Electro Mechanical
CDG
1962
50
40
Low
Yes
Medium
Low
10.52
New Norfolk
NN-SCTC-J1
NN-JDIT
Teleprotection
Static
937B
1978
34
20
Low
Yes
Extreme
Medium
11.44
New Norfolk
NN-SCTC-K1
NN-KDIT
Teleprotection
Static
937B
1978
34
20
Low
Yes
Extreme
Medium
11.44
Page 50 of 54
Location
Scheme
Device ID
Device Description
Technology
Model
Manufactured
Age
Average
Defect Age
Support
Spares
Maintenance
Functionality
Health
Score
Meadowbank
MB-SCTC-A1
MB-A121A
Main A protection
Static
RAZOA
1987
25
20
Low
Yes
Medium
Low
10.54
Meadowbank
MB-SCTC-A1
MB-A121B
Main B protection
Static
LZ92-1
1987
25
20
Low
Yes
Medium
Low
10.54
Meadowbank
MB-SCTC-A1
MB-A164
Static
PSEL3002
1987
25
20
Low
Yes
Medium
Low
10.54
Meadowbank
MB-SCTC-B1
MB-B164
Static
PSWS190
1987
25
20
Low
Yes
Medium
Low
10.54
Meadowbank
MB-SCTC-B1
MB-B121A
Main A protection
Static
MDT-B151
1981
31
20
Low
Yes
Medium
Low
11.14
Meadowbank
MB-SCTC-B1
MB-B121B
Main B protection
Static
THR
1981
31
20
Low
Yes
Medium
Low
11.14
North Hobart
NH-SCTC-A4
NH-A151CH
CB Fail Protection
Static
CTIG39
1976
36
20
Low
No
Medium
Low
17.64
North Hobart
NH-SCTC-A4
NH-A187
Main A protection
Electro Mechanical
DSF7
1976
36
40
Low
Yes
Extreme
Low
11.82
North Hobart
NH-SCTC-B4
NH-B151CH
CB Fail Protection
Static
CTIG39
1976
36
20
Low
No
Medium
Low
17.64
North Hobart
NH-SCTC-B4
NH-B187
Main A protection
Electro Mechanical
DSF7
1976
36
40
Low
Yes
Extreme
Low
11.82
New Norfolk
NN-SCTC-D1
NN-D121A
Main A protection
Static
RAZOA
1986
26
20
Low
Yes
Medium
Low
10.64
New Norfolk
NN-SCTC-D1
NN-D164
Static
PSEL3000
1986
26
20
Low
No
Medium
Low
16.64
New Norfolk
NN-SCTC-D1
NN-DFL
Fault Locator
Static
7SE121
1986
26
20
Low
Yes
Medium
Medium
8.64
New Norfolk
NN-SCTC-D1
NN-D121B
Main B protection
Static
LZ92-1
1987
25
20
Low
Yes
Medium
Low
10.54
New Norfolk
NN-SCTC-E1
NN-E121B
Main B protection
Static
LZ92-1
1987
25
20
Low
Yes
Medium
Low
10.54
New Norfolk
NN-SCTC-E1
NN-E164
Static
PSEL3000
1987
25
20
Low
No
Medium
Low
16.54
New Norfolk
NN-SCTC-E1
NN-E121A
Main A protection
Static
RAZOA
1986
26
20
Low
Yes
Medium
Low
10.64
New Norfolk
NN-SCTC-F1
NN-FFL
Fault Locator
Static
7SE121
1986
26
20
Low
Yes
Medium
Medium
8.64
Page 51 of 54
Location
Scheme
Device ID
Device Description
Technology
Model
Manufactured
Age
Average
Defect Age
Support
Spares
Maintenance
Functionality
Health
Score
New Norfolk
NN-SCTC-F1
NN-F121A
Main A protection
Static
RAZOA
1987
25
20
Low
Yes
Medium
Low
10.54
New Norfolk
NN-SCTC-F1
NN-F121B
Main B protection
Static
LZ92-1
1987
25
20
Low
Yes
Medium
Low
10.54
New Norfolk
NN-SCTC-F1
NN-F164
Static
PSEL3000
1987
25
20
Low
No
Medium
Low
16.54
New Norfolk
NN-SCTC-J1
NN-J121B
Main B protection
Static
LZ92-1
1987
25
20
Low
Yes
Medium
Low
10.54
New Norfolk
NN-SCTC-J1
NN-J164
Static
RXIG22
1987
25
20
Medium
Yes
Medium
Low
9.54
New Norfolk
NN-SCTC-K1
NN-K121B
Main B protection
Static
LZ92-1
1987
25
20
Low
Yes
Medium
Low
10.54
New Norfolk
NN-SCTC-K1
NN-K164
Static
RXIG22
1987
25
20
Medium
Yes
Medium
Low
9.54
New Norfolk
NN-SCTC-P1
NN-P121A
Main A protection
Static
RAZOA
1987
25
20
Low
Yes
Medium
Low
10.54
New Norfolk
NN-SCTC-P1
NN-P121B
Main B protection
Static
LZ92-1
1987
25
20
Low
Yes
Medium
Low
10.54
New Norfolk
NN-SCTC-P1
NN-P164
Static
PSEL3000
1987
25
20
Low
No
Medium
Low
16.54
New Norfolk
NN-SCTC-P1
NN-P125
Synchronism Check
Static
2SY110K18
1987
25
20
Low
No
Medium
Medium
14.54
New Norfolk
NN-SCTC-R1
NN-R121A
Main A protection
Static
RAZOA
1986
26
20
Low
Yes
Medium
Low
10.64
New Norfolk
NN-SCTC-R1
NN-R164
Static
PSEL3000
1986
26
20
Low
No
Medium
Low
16.64
New Norfolk
NN-SCTC-R1
NN-R121B
Main B protection
Static
LZ92-1
1987
25
20
Low
Yes
Medium
Low
10.54
Paloona Tee
PA-SCTC-B1
PA-B121A
Main A protection
Electro Mechanical
LH1D
1963
49
40
Low
No
Extreme
Low
18.47
Paloona Tee
PA-SCTC-B1
PA-B121B
Main B protection
Electro Mechanical
RXAP6302
1968
44
40
Low
No
Extreme
Low
18.22
Paloona Tee
PA-SCTC-B1
PA-B164
Static
PSWS190
1981
31
20
Low
Yes
Medium
Low
11.14
Palmerston
PM-SCTC-O1
PM-O164
Static
RSAS1110
1974
38
20
Low
Yes
High
Low
12.84
Page 52 of 54
Location
Scheme
Device ID
Device Description
Technology
Model
Manufactured
Age
Average
Defect Age
Support
Spares
Maintenance
Functionality
Health
Score
Palmerston
PM-SCTC-O1
PM-O121A
Main A protection
Static
YTS
1977
35
20
Low
Yes
Medium
Low
11.54
Palmerston
PM-SCTC-O1
PM-O121B
Main B protection
Static
PDS2000B
1977
35
20
Low
Yes
Medium
Low
11.54
Palmerston
PM-SCTC-R1
PM-R121B
Main B protection
Static
THR
1984
28
20
Low
Yes
Medium
Low
10.84
Palmerston
PM-SCTC-R1
PM-R164
Electro Mechanical
CTU
1972
40
40
Low
Yes
Medium
Low
10.02
Palmerston
PM-SCTC-R1
PM-R121A
Main A protection
Electro Mechanical
RXAP6302
1968
44
40
Low
No
Extreme
Low
18.22
Palmerston
PM-SCTC-Y1
PM-Y121B
Main B protection
Static
PDS2000B
1978
34
20
Low
Yes
Medium
Low
11.44
Palmerston
PM-SCTC-Y1
PM-Y121A
Main A protection
Static
THR
1979
33
20
Low
Yes
Medium
Low
11.34
Palmerston
PM-SCTC-Y1
PM-Y164B
Static
PSWS190
1979
33
20
Low
Yes
Medium
Low
11.34
Palmerston
PM-SCTC-Z1
PM-Z121A
Main A protection
Static
THR
1979
33
20
Low
Yes
Medium
Low
11.34
Palmerston
PM-SCTC-Z1
PM-Z164B
Static
PSWS190
1979
33
20
Low
Yes
Medium
Low
11.34
Palmerston
PM-SCTC-Z1
PM-Z121B
Main B protection
Static
PDS2000B
1978
34
20
Low
Yes
Medium
Low
11.44
Rokeby
RK-SCTC-A1
RK-A187A
Cable Differential Protection
Electro Mechanical
DPDL120
1968
44
40
Low
Yes
Medium
Low
10.22
Rokeby
RK-SCTC-A1
RK-A187B
Electro Mechanical
DPDL120
1968
44
40
Low
Yes
Medium
Low
10.22
Rokeby
RK-SCTC-B1
RK-B187B
Electro Mechanical
DPDL120
1968
44
40
Low
Yes
Medium
Low
10.22
Rokeby
RK-SCTC-B1
RK-B187A
Electro Mechanical
DPDL120
1968
44
40
Low
Yes
Medium
Low
10.22
Sheffield
SH-SCTC-L1
SH-LDR
Disturbance Recorder
Microprocessor
IMS8
1988
24
15
High
No
High
High
11.25
Sheffield
SH-SCTC-L1
SH-L121
Main B protection
Static
QUADRAMHO
1987
25
20
Medium
Yes
Medium
Low
9.54
Sheffield
SH-SCTC-L1
SH-L185
Main A protection
Static
MPC-SB201
1987
25
20
Low
Yes
Extreme
Low
12.54
Page 53 of 54
Location
Scheme
Device ID
Device Description
Technology
Model
Manufactured
Age
Average
Defect Age
Support
Spares
Maintenance
Functionality
Health
Score
Tarraleah
TA-SCTC-B1
TA-B121A
Main A protection
Static
MDT-B151
1981
31
20
Low
Yes
Medium
Low
11.14
Tarraleah
TA-SCTC-B1
TA-B164
Static
PSWS190
1981
31
20
Low
Yes
Medium
Low
11.14
Tarraleah
TA-SCTC-B1
TA-B121B
Main B protection
Static
PDS2000B
1980
32
20
Low
Yes
Medium
Low
11.24
Tarraleah
TA-SCTC-C1
TA-C121A
Main A protection
Static
PYTS101
1979
33
20
Low
Yes
Medium
Low
11.34
Tarraleah
TA-SCTC-C1
TA-C121B
Main B protection
Static
PDS2000B
1979
33
20
Low
Yes
Medium
Low
11.34
Tarraleah
TA-SCTC-C1
TA-C164
Static
PSWS190
1979
33
20
Low
Yes
Medium
Low
11.34
Tarraleah
TA-SCTC-D1
TA-D121A
Main A protection
Static
PYTS101
1979
33
20
Low
Yes
Medium
Low
11.34
Tarraleah
TA-SCTC-D1
TA-D121B
Main B protection
Static
PDS2000B
1979
33
20
Low
Yes
Medium
Low
11.34
Tarraleah
TA-SCTC-D1
TA-D164
Static
PSWS190
1980
32
20
Low
Yes
Medium
Low
11.24
Tungatinah
TU-SCTC-B1
TU-B121B
Main B protection
Static
PYTS101
1982
30
20
Low
Yes
Medium
Low
11.04
Tungatinah
TU-SCTC-B1
TU-B121A
Main A protection
Static
PDS2000B
1979
33
20
Low
Yes
Medium
Low
11.34
Tungatinah
TU-SCTC-B1
TU-B164
Static
PSWS190
1979
33
20
Low
Yes
Medium
Low
11.34
Page 54 of 54

Transmission Line Protection Asset Management

Transcription

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