Attachment 11.8
Jacobs:
Recommended bushfire risk
reduction strategies for
SA Power Networks
October 2014
Recommended Bushfire Risk Reduction Strategies
FOR SA POWER NETWORKS
Final Report| October 2014
Recommended Bushfire Risk Reduction Strategies
Recommended Bushfire Risk Reduction Strategies
Document title:
Recommended Bushfire Risk Reduction Strategies
Revision:
Final V7.0
Date:
28 October 2014
Prepared by:
Phillip Webb
Approved by:
Greg Whicker
File name:
Bushfire Risk Reduction Strategies_Final Report_V7_281014
Jacobs Group (Australia) Pty Limited
ABN 37 001 024 095
Level 5, 33 King William Street
Adelaide SA 5000 Australia
PO Box 8291
Station Arcade SA 5000 Australia
T +61 8 8424 3800
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www.Jacobs.com
COPYRIGHT: The concepts and information contained in this document are the property of Jacobs Group (Australia) Pty Limited. Use or copying
of this document in whole or in part without the written permission of Jacobs constitutes an infringement of copyright.
Recommended Bushfire Risk Reduction Strategies
Contents
1.
Executive Summary
1
2.
Introduction
3
3.
Fire Start History
4
3.1.
3.2.
3.3.
4
5
5
Fire Start Statistics - Summary
Fire Start Reduction Calculations
State-specific issues
4.
Summary Analysis of Bushfire Risk Mitigation Strategies
6
5.
Detailed Analysis of Bushfire Risk Mitigation Strategies
10
5.1.
33kV, 19kV and 11kV SCADA Reclosers
11
5.1.1.
5.1.2.
5.1.3.
5.1.4.
5.1.5.
5.1.6.
5.1.7.
Description
Background
Existing units
Modern Units
Industry Practice
Costs
Discussion and implementation strategy
11
11
11
12
13
13
13
5.2.
Undergrounding or insulating LV, 11kV and 33kV Lines
15
5.2.1.
5.2.2.
5.2.3.
5.2.4.
5.2.5.
Description
Background
Industry Practice
Route Lengths and Costs
Discussion and implementation strategy
15
15
15
16
16
5.3.
Increased Frequency of Asset Inspections
18
5.3.1.
5.3.2.
5.3.3.
5.3.4.
5.3.5.
5.3.6.
Description
Background
Industry Practice
Effectiveness
Costs
Discussion and implementation strategy
18
18
19
19
20
20
5.4.
Thermographic Inspections in H/MBFRA
21
5.4.1.
5.4.2.
5.4.3.
5.4.4.
5.4.5.
Description
Background
Industry Practice
Costs
Discussion and implementation strategy
21
21
22
22
22
5.5.
Install Surge Arrestors
23
5.5.1.
5.5.2.
5.5.3.
5.5.4.
5.5.5.
Description
Background
Industry Practice
Costs
Discussion and implementation strategy
23
23
23
23
24
5.6.
Ground Fault Neutralising Technology
25
i
Recommended Bushfire Risk Reduction Strategies
6.
5.6.1.
5.6.2.
5.6.3.
5.6.4.
5.6.5.
5.6.6.
Description
Background
Industry Practice
Efficiency
Typical Costs
Discussion and Implementation Strategy
25
25
25
26
26
27
5.7.
Re-construct Metered Mains
28
5.7.1.
5.7.2.
5.7.3.
5.7.4.
Description
Background
Industry Practice
Implementation Strategy
28
28
29
29
5.8.
Backup Protection
31
5.8.1.
5.8.2.
5.8.3.
5.8.4.
Requirement
Background
Industry Practice
Implementation Strategy
31
31
32
32
Recommended Strategies for AER Submission
33
6.1.
6.2.
Good Industry Practice
Detailed Strategy Analyses - Summary
33
34
6.2.1.
6.2.2.
6.2.3.
6.2.4.
6.2.5.
6.2.6.
6.2.7.
6.2.8.
6.2.9.
General
SCADA reclosers for 33kV, 19kV and 11kV
New LV, 11kV and 33kV construction
Asset inspection frequency
Thermographic inspections
Surge arrestors
Ground fault neutralising technology
Re-construct metered mains
Backup protection
34
34
34
35
35
35
35
36
36
6.3.
Recommended Strategies and Estimated Costs
37
7.
References
38
8.
Appendix 1: SA Power Networks fire report - Rod Air Gaps
39
9.
Appendix 2: SA Power Networks fire report - hot joint
40
10. Attachment 1: Summary CV Information
42
ii
Recommended Bushfire Risk Reduction Strategies
1. Executive Summary
Jacobs1 was engaged by SA Power Networks to review their bushfire risk management practices and assist
with the development of strategic options for possible inclusion in SA Power Networks’ AER reset submission.
The scope of work included a review of:
-
SA Power Networks’ current practices and procedures for bushfire risk management;
-
SA Power Networks’ fire start history to establish root causes;
-
Current research on bushfire risk management practices for electricity distributors;
-
The relevant findings of the Victorian Bushfires Royal Commission and the subsequent Powerline
Bushfire Safety Taskforce;
-
Bushfire Risk Management initiatives by Distribution Network Service Providers in other Australian
states.
Jacobs considers it prudent for SA Power Networks to implement additional risk mitigation strategies to ensure
that it complies not only with regulations, but also with good industry practice that has evolved in recent years
following extreme events interstate including:
-
Improved asset and risk management processes;
-
Upgrading of obsolete equipment to modern construction;
-
The installation of modern remote controlled technology for control, fault detection & protection;
-
Efficient and effective asset inspection and monitoring procedures that trigger appropriate and timely
maintenance regimes; and
-
Trialling of new technology.
Jacobs was requested to apply the network management experience and engineering judgement of its project
team to recommend a practical, cost-effective package of risk mitigation strategies that would allow SA Power
Networks to operate in a manner consistent with current “good industry practice”.
The eight recommended strategies described in Section 6 of this report have been chosen to target the issues
and areas of highest fire start risk, accommodate SA Power Network’s capability to execute, and provide
optimum fire risk mitigation benefits at a modest cost. Table 1 summarises these recommended strategies and
costs.
SA Power Networks should apply risk management principles to assess the probability and consequence of fire
starts for each of its feeders in high bushfire risk areas. These risk assessments will assist selection of the
appropriate strategy and priority for each feeder within a staged work program.
1
Jacobs Engineering Group acquired Sinclair Knight Merz in December 2013.
1
Recommended Bushfire Risk Reduction Strategies
Table 1: Recommended Bushfire Risk Reduction Strategies and Estimated Costs2
Strategy
No.
1
Section and content
2015/16
2016/17
2017/18
2018/19
2019/20
5.1 Replace 33kV, 19kV and
11kV reclosers with SCADA
controlled modern units
$3.6m
$3.6m
$3.6m
$3.6m
$3.6m
$18.0m
2
5.2 Undergrounding or insulating
LV, 11kV and 33kV lines
$5.7m
$5.9m
$3.8m
$6.3m
$4.9m
$26.6m
3
5.3 Increase the frequency of
asset inspections
$2.3m
$2.6m
$2.7m
$2.7m
$2.7m
$13.0m
4
5.4 Extend and increase the
frequency of thermographic asset
inspections
$0.5m
$0.5m
$0.5m
$0.5m
$0.5m
$2.5m
5
5.5 Replace rod air gaps and
current limiting arcing horns with
Surge Arrestors
$2.4m
$2.4m
$2.4m
$2.4m
$2.4m
$12.0m
6
5.6 Undertake field simulation,
testing and trial installation of
Ground Fault Neutralisation
Technology
$1.0m
$4.0m
$5.0m
$2.0m
$12.0m
7
5.7 Reconstruct metered mains
$4.1m
$8.2m
$8.2m
$8.2m
$4.1m
$32.8
8
5.8 Backup protection
$2.9m
$3.0m
$3.4m
$3.6m
$5.6m
$18.5m
$21.5m
$27.2m
$28.6m
$32.3m
$25.8m
$135.6m
Totals
2
Total
All costs are in June 2015 dollars
2
Recommended Bushfire Risk Reduction Strategies
2. Introduction
Jacobs was engaged by SA Power Networks to review their bushfire risk management practices and assist with
the development of strategic options for possible inclusion in SA Power Networks’ AER reset submission for
2015-2020.
The review was conducted by senior Jacobs personnel Phillip Webb, Terry Krieg and Greg Whicker. Summary
CV information is included as Attachment 1.
The scope of work included:
Consult with key SA Power Networks managers to discuss the effectiveness of current bushfire risk
management strategies and those currently being considered;
Carry out a detailed review of SA Power Networks’ fire start history to establish root causes (summarised in
Section 3 of this report);
Carry out a review of:
-
SA Power Networks’ current practices and procedures for bushfire risk management;
-
Current research on bushfire risk management practices for electricity distributors;
-
The relevant findings of the Victorian Bushfires Royal Commission (VBRC) and the subsequent
Powerline Bushfire Safety Taskforce (PLBSTF);
-
The Bushfire Risk Management initiatives by Distribution Network Service Providers (DNSPs) in other
Australian states.
Carry out a preliminary assessment of potential risk mitigation strategies considering benefits, limitations
and their effectiveness in reducing the number of fire starts (summarised in Section 4 of this report).
Identify those strategies which are either ‘current practice’, ‘not applicable to SA Power Networks’, or of ‘low
benefit’ to exclude these strategies from detailed analysis;
Carry out a detailed analysis of those ‘included strategies’ providing an approximate cost estimate for each
strategy (summarised in Section 5 of this report); and
Use the network experience and engineering judgement of Jacobs’ project team to recommend a practical,
cost-effective package of risk mitigation strategies that would allow SA Power Networks to operate in a
manner consistent with current ‘good industry practice’. These strategies, which may be presented to the
AER as part of SA Power Networks’ Reset submission, are discussed in Section 6 of this report.
3
Recommended Bushfire Risk Reduction Strategies
3. Fire Start History
This Section summarises the findings from a detailed review of SA Power Networks’ fire start history to establish
root causes.
3.1.
Fire Start Statistics - Summary
SA Power Networks records comprehensive data on fire starts that have been associated with its network
assets. It classifies areas of the State into one of three bushfire risk categories: High Bushfire Risk Area
(HBFRA), Medium Bushfire Risk Area (MBFRA) and Non-Bushfire Risk Area (NBFRA).
The MBFRA is an area where a fire could start and readily escape to an unrestricted area of flammable material
causing Moderate Consequences3. The relevant parts of the state are shown in the maps in Schedule 4 of the
Electricity (Principles of Vegetation Clearance) Regulations 2011.
The HBFRA is an area where a fire could start and readily escape into an unrestricted area of flammable
material causing Major to Catastrophic Consequences4, broadly classified as areas which receive 600mm or
more rainfall.
The BFRA as defined in the Electricity (Principles of Vegetation Clearance) Regulations 1996 Schedule 3 is the
combination of the MBFRA and the HBFRA. The Non BFRA is also as defined in the Regulations.
Jacobs carried out a detailed assessment of SA Power Networks’ fire start history to determine root causes and
number of fire starts by voltage and bushfire risk area. Table 2 shows the number of fire starts per 1,000kms
across all voltages and all bushfire risk areas for the period 1 January, 2008 to 31 December, 2012. The
average number of fire starts over this period is 67 per annum, of which 53 per annum are in the HBFRA and
MBFRA. As the length of line influences the potential for a fire start, the number of fire starts per 1,000kms was
calculated to determine which voltage was the highest fire risk.
Table 2: Number of Fire Starts per 1,000 kms
Voltage
Bushfire Risk Area
HBFRA
MBFRA
NBFRA
LV
7.6 &11kV
33kV
19kV
66kV
9
4
2
11
8
10
24
13
5
2
1
0
8
1
0
This table shows that most fire starts per 1,000kms in both the MBFRA and HBFRA are from the 33kV
Network.
3
4
Adapted from AS/NZS ISO 31000:2009 Risk Management – Principles and Guidelines
Ibid
4
Recommended Bushfire Risk Reduction Strategies
3.2.
Fire Start Reduction Calculations
The approach adopted by Jacobs in estimating the potential fire start reduction for a particular risk mitigation
strategy was to pro-rata the reduction on the basis of ‘fire starts per route km’ for which the strategy is applied.
A moderate efficiency factor between 1 and 2 was also applied, recognising that each strategy would be
targeted to be applied to the locations and assets with the highest risk and highest fire start potential first. In
some cases, however, an efficiency factor of less than 1 was applied because there is less than a 1 to 1 benefit
from implementation. For example, increasing the frequency of inspections across all fire risk areas will improve
the detection of fire start defects, but will not eliminate them.
3.3.
State-specific issues
South Australia experienced extreme bushfires on 16 February 1983 with 28 lives lost. That, and other factors,
triggered the evolution of comprehensive bushfire risk management processes within SA Power Networks
(previously known as ETSA).
During the past decade, Jacobs has monitored SA Power Networks’ annual Fire Danger Level Exercise and the
refinement of its Bushfire Risk Management system. These processes are now considered mature,
comprehensive, appropriately documented and well managed.
SA Power Networks’ construction standards vary from those interstate in several ways that assist with reducing
bushfire starts:
(i)
(ii)
(iii)
Concrete and steel poles (Stobie poles) are used in SA, whereas wooden poles are generally used
interstate. Stobie poles are of consistent mechanical strength, are not combustible and are not
prone to termite attack. This results in longer life and a lower likelihood of failure in high winds;
Steel cross arms are used in SA for all voltages in bushfire risk areas compared to a wider use of
timber interstate. Unlike wooden cross arms, steel cross arms are not combustible and do not
catch fire during events such as flashover (caused by conductors on cross arms) or lightning
surges;
In many locations, SA Power Networks uses a common multiple earthed neutral (CMEN)
arrangement that provides a low impedance path for fault current back to the source zone
substation. CMEN, coupled with steel cross arms and steel poles, provides low impedance for
earth fault currents resulting in generally fast protection operation and clearance.
However, even a single fire start on an extreme fire risk day in a location with hilly terrain and large quantities of
dry grass and/or forest fuels could result in another catastrophic bushfire in SA. The high population densities
within some areas of the Mount Lofty Ranges, in particular, significantly increase the consequences of a fire
start.
5
Recommended Bushfire Risk Reduction Strategies
4. Summary Analysis of Bushfire Risk Mitigation Strategies
This Section summarises the findings from a preliminary assessment of potential risk mitigation strategies
considering benefits, limitations and their effectiveness in reducing the number of fire starts.
The following table lists risk mitigation strategies that have been sourced by Jacobs from:
-
The current bushfire mitigation practices of Australian DNSPs;
The outcomes of the VBRC into Victoria’s Black Saturday bushfires; and
The subsequent report of the PLBSTF.
These strategies have been categorised into three main areas:
-
Those that target the direct reduction of fire starts, such as insulated conductors and undergrounding;
Those that improve the efficiency of bushfire risk management, such as fire risk consequence
modelling; and
Those that improve safety through flexible, remotely controlled equipment, such as modern circuit
reclosing devices with supervisory control and data acquisition (SCADA).
Some strategies can provide benefits in more than one category.
The final column in the following table indicates whether a particular strategy is included in the detailed analysis
in Section 5 of this report, and provides the reason for its exclusion (if applicable). Strategies that, at best, could
only affect 10% or less of the annual fire starts have been excluded due to their low impact on the fire start risk
and the expectation that other recommended strategies are likely to resolve that specific fire start risk. For
example, ‘bird covers on bushings’ is effectively addressed when bare conductors are replaced with insulated or
underground conductors.
Table 3: Summary of Preliminary Analysis of Strategies
Strategy Description
Details
Source/Basis
Included/Excluded Main
Category/ Reason
Replace 33kV, 11kV and
Replace aging hydraulic reclosers
PLBSTF, Essential
Included
19kV reclosers with
which have limited setting capability
Energy, SP AusNet,
SCADA controlled modern
with SCADA controlled units with
Western Power
Efficiency/Safety
units
flexible settings
Underground or insulated
Installation of underground or
PLBSTF, Western
Included
HV in HBFRA
insulated conductor in targeted areas
Power, SP AusNet
Insulated conductor eg Hendrix
Essential Energy
Fire Start Reduction
conductor (3 insulated cables spaced
apart and supported with a
catenary/ground wire).
6
Recommended Bushfire Risk Reduction Strategies
Strategy Description
Details
Source/Basis
Included/Excluded Main
Category/ Reason
Underground or insulated
Installation of underground or
LV in HBFRA
insulated conductor eg ABC.
PLBSTF
Included
Fire Start Reduction
LV private line
A distributor-funded incentive to
Essential Energy
Not specifically included
undergrounding incentive
underground Private LV lines that
– See similar issue
scheme
have defects, vegetation management
identified as “Metered
or end-of- life issues
Mains”
Targeted asset
Outcomes of the application of the fire
SP AusNet,
Not specifically included
replacement based on fire
consequence model to a network will
Essential Energy
– current practice
consequence model
be to target bushfire risk mitigation
Efficiency
projects for specific assets identified
as presenting extreme risk.
Field work standards
Development and monitoring of field
All DNSPs
work construction and operational
Not specifically included
– current practice
activities and methods to ensure
Distribution entity staff and
contractors do not create fire start
risks.
Increase the frequency of
Increase the frequency and extent of
asset inspections
asset inspections.
PLBSTF, All DNSPs
Included
Fire Start Reduction
Extend and increase the
Extend the practice of thermal
frequency of thermographic
inspections
asset inspections
All DNSPs
Included
Fire Start Reduction
7
Recommended Bushfire Risk Reduction Strategies
Replace rod air gaps and
Installation of surge arrestors on pole
Eastern States
current limiting arcing
top transformers is standard practice
DNSPs
horns with Surge Arrestors
in Eastern state DNSPs. This is now
Included
Fire Start Reduction
also standard practice for SA Power
Not standard
Networks, but there is a significant
construction for high
legacy of rod gaps and current limiting
fire risk areas
arcing horns.
Undertake field simulation,
Based on trial results, install GFN
PLBSTF
testing and trial installation
technology in substations supplying
Future projects subject to
of Ground Fault
high bushfire risk areas.
results of trials and
Neutralisation (GFN)
Included on a trial basis.
interstate utility feedback
Technology
Fire Start
Reduction/Safety
Reconstruct metered Mains
Inspect to assess condition and
SA Power Networks
Included
address issues - LV beyond metering
Fire start reduction/safety
point in rural areas.
Backup protection
Realign feeder protection to the
All DNSPs
Included
requirements of the National
Fire Start Reduction
Electricity Rules
Clearing of Hazardous
Trees
Change legislation to permit the
clearing of hazardous trees.
PLBSTF, SA Power
Networks,
Not specifically Included
Low benefit
SP AusNet, Essential
Energy
LIDAR Technology
Vegetation management
Investigate and develop the
application of LIDAR technology
towards vegetation identification and
analysis in relation to bushfire risk.
Ergon
Manage vegetation by inspection and
cutting as required by legislation
All DNSPs
Included in other parts of
the Reset submission
Efficiency
Not specifically included
– Existing practice
8
Recommended Bushfire Risk Reduction Strategies
Fire consequence model
development
Industry Research
Network performance and
Planning
Maintenance Program
Reporting and investigation
of fire starts
Analysis of information
from other sources
Distribution Businesses
Develop fire consequence heat maps
based on recognized fire propagation
models and apply this to network
assets in high bushfire risk areas.
These simulations are able to apply
fire footprints initiated at network
assets and the consequential losses
including dwellings. This information
provides a risk/location profile that
leads to targeted bushfire risk
mitigation projects.
Essential Energy, SP
AusNet
Monitor, evaluate and contribute
towards academic and industry
research into the management,
prevention and mitigation of bushfires.
All DNSPs
Monitor the performance of feeders
for reliability and fire starts and
implement remediation work for
poorly performing feeders especially
in risk areas
All DNSPs
Targeted refurbishment programs for
specific assets that have end of life
failures or type defects
All DNSPs
Comprehensive and detailed
monitoring and reporting of fire starts.
Fire start investigation and analysis
provide an opportunity to review
performance and adopt mitigating
strategies based on historical events
and real life experience.
All DNSPs
Continuous monitoring of fire start
experiences and industry
investigations or public reports.
Working with other distributors to
share information and experience in
regard to fire starts where the
opportunity exists.
All DNSPs
Western Power
developing its own
model but similar
basis as per Eastern
states.
Included, but SA Power
Networks has a project in
progress
Efficiency
Not specifically included
– current practice
Not specifically included
– current practice
Not specifically included
– current practice
Not specifically included
– current practice
Not specifically included
– current practice
9
Recommended Bushfire Risk Reduction Strategies
5. Detailed Analysis of Bushfire Risk Mitigation Strategies
Jacobs carried out a detailed assessment of each of the ‘Included’ strategies listed in Table 3. Some key
strategies, particularly ‘fire consequence model development’, are already being progressed by SA Power
Networks.
This Section discusses the eight strategies subsequently ‘Recommended’ by Jacobs. These particular
strategies and implementation options were selected to target the issues and areas of highest fire start risk,
accommodate SA Power Network’s capability to execute, and provide optimum fire risk mitigation benefits at a
modest cost.
Note that:
-
The underpinning network data and fire statistics have been provided by SA Power Networks; and
The key costs have been sourced from SA Power Networks and the PLBSTF report.
10
Recommended Bushfire Risk Reduction Strategies
5.1.
33kV, 19kV and 11kV SCADA Reclosers
5.1.1.
Description
SA Power Networks and other Australian DNSPs have many ageing HV automatic circuit reclosers in service
that should be replaced with modern SCADA controlled units to reduce the fire start risk and improve safety for
the community and power line workers.
5.1.2.
Background
33kV, 19kV &11kV reclosers are self-contained circuit breakers with inbuilt fault detection mechanisms and
control systems to allow reclosing. The reclosing function restores electricity following a transient fault. If the
fault is permanent, the device remains open or “locks out” until manually reset. These units are constructed to
be pole mounted and are usually installed on overhead line pole structures or on stub-poles in substations.
The ageing types predominantly use hydraulic mechanisms for fault detection and operation.
5.1.3.
Existing units
The limitations of existing units are mainly associated with inflexible protection and control settings and an
inability to remotely monitor or control their operation.
Protection setting flexibility
The fault detection settings, namely duration and the trip close sequences and timings, are limited and fixed
once set. Changes to these parameters require the unit to be returned to the workshop and internally modified.
The reclose time can potentially reduce the risk of fire start, as it has been found that longer reclose times
increase the probability of a fault-caused fire start (Marxsen et al 2012).
Remote Control and Monitoring
These units are unable to be remotely controlled or monitored. They are unable to be remotely switched off
during extreme fire danger events and require either:
-
Upstream devices to be switched off (involving more network & customers than required to be
disconnected); or
Field staff to attend to disable reclosing or to disconnect or re-connect prior to or following a bushfire
event. Sending staff into areas where the fire danger conditions are extreme would greatly risk their
personal safety.
In evidence given at the VBRC5, it was agreed that the probability of a fire starting from a downed conductor
increased significantly if the recloser operated slowly and operated a number of times. Disabling the reclose
function and setting the recloser to clear faults as quickly as possible, significantly reduces the risk of a fire
starting from a line fault. Tests by Marxsen et al (2012) confirmed this for a “worst case fire condition”.
5
Transcript of Victorian Bushfires Royal Commission, Tuesday 17 November 2009, pp 11103-11106
11
Recommended Bushfire Risk Reduction Strategies
Weather conditions change dramatically on extreme fire weather days. The following chart shows the turbulent
and sudden increases in mean wind speeds and wind gusts at Williamtown Automatic Weather Station on
13/10/13, when a fire affecting 200 homes started from electricity assets. Such weather charts are typical of
extreme fire weather days.
Williamtown
Fire Start time
100
80
60
40
20
0
10:30
11:30
12:30
13:30
14:30
15:30
16:30
17:30
18:30
19:30
20:30
21:30
22:30
23:30
00:30
01:30
02:30
03:30
04:30
05:30
06:30
07:30
08:30
09:00
10:00
10:20
11:00
11:30
12:30
13:30
14:30
15:00
16:00
17:00
17:30
18:30
19:30
20:30
21:00
22:00
22:41
22:47
23:00
23:26
00:00
00:23
00:33
01:00
01:39
01:58
02:10
02:33
02:47
03:30
04:30
05:30
06:30
07:30
08:30
09:30
10:30
11:30
12:30
13:30
14:30
15:30
16:30
17:30
18:30
19:30
20:30
21:30
22:30
23:00
23:51
00:30
01:30
02:07
02:49
03:30
04:30
05:30
06:30
07:30
08:30
09:30
Wind Spd
(km/h)
12/10/2013
13/10/2013
14/10/2013
Wind Gust
(km/h)
15/10/2013
Placing a recloser to fast acting, single shot fault clearing mode reduces fire start risk and SCADA control
avoids the deployment of line crews which (a) takes too long and (b) in extreme fire danger conditions is a
safety risk.
Many of SAPN’s reclosers are not remotely controllable, especially on SWER, as per the table below:
Table 4: Reclosers not on SCADA
5.1.4.
Area
33kV
11/7.6kV
19kV
TOTAL
HBFRA
13
124
69
206
MBFRA
27
87
367
481
TOTAL
40
211
436
687
Modern Units
Modern reclosers have a wide range of protection settings that can be programmed and changed in-situ.
SCADA control enables remote changing of protection and control functions eg disabling or enabling reclose,
opening, closing and status and load monitoring. SCADA control also provides the capability for SA Power
Networks to remotely exercise their statutory ability to disconnect under specific extreme conditions in order to
prevent fire starts from network assets.
Modern reclosers are generally more sensitive than the older types at fault detection and can also trip at higher
speeds. The range of settings available is more comprehensive and can be adjusted for optimum protection
12
Recommended Bushfire Risk Reduction Strategies
performance given the specific network characteristics. The addition of SCADA control provides the same
range of remote control and monitoring functions that have previously only been available at zone and terminal
substations.
Holmes (2011, 15 September) reported on the recent manufacture of a “…new ACR to dramatically reduce the
injected arc energy under SWER fault conditions, to levels that can significantly reduce the probability of
bushfire ignition even under high risk conditions…”. Transmission and Distribution magazine reported in their
February/March 2012 edition that after successful trials “…projects are in place to install large quantities of
Smart SWER Reclosers in bushfire prone areas…(in Victoria)” (T&D p. 13)
5.1.5.
Industry Practice
Most Australian DNSPs are now installing modern SCADA controlled reclosers for improved protection
capability, remote control and setting of the reclose function and trip sequences.
Recommendation 32 of the VBRC requires that the reclose function on distribution power line reclosers is
disabled in high-risk areas on total fire ban days.
The practice of disabling reclose on high fire risk days6 has been standard practice in SA Power Networks for
many years. In many cases, this has been achieved manually by site attendance when time and resources
permit.
5.1.6.
Costs
The approximate cost of replacing an ageing recloser with a modern unit is about $120,000, which includes
SCADA and the associated communications equipment.
5.1.7.
Discussion and implementation strategy
During the years 2008 to 2012, over 50% of SA Power Networks’ fire starts occurred on 11kV and 7.6kV
networks. The 33kV network has a lower number of fire starts but has a higher rate of fire starts per 1,000 route
kms.
The implementation of Bushfire Risk Reduction Strategy (BRRS) no. 1 – the recloser replacement program – is
impacted by BRRS no. 8 – Back-up Protection. It is estimated that implementing this latter strategy will account
for the replacement of 55 of the 206 non-SCADA reclosers in the HBFRA. Hence, the remaining 151 reclosers
will be replaced as part of BRRS no. 1. SA Power Networks advises that there is capacity to replace around 40
reclosers per annum, which will be comprised of 30 per annum for strategy no. 1 and 11 per annum for strategy
no. 8, and hence the conversion of reclosers to SCADA control in the HBFRA is expected to be completed
within the 2015-2020 five year period.
Priority order should be replacing 33kV and 11kV reclosers, followed by 19kV reclosers. Once the HBFRA is
completed, consideration should be given to extending the programme to the MBFRA. The priority order
should be based on risk management principles and should consider:
6
Total Fire Ban days with mean wind speeds forecast to be at least 45km/h
13
Recommended Bushfire Risk Reduction Strategies
1)
Feeder reliability history;
2)
Fire start history;
3)
Length of line protected by the recloser;
4)
Number of Total Fire Ban (TOBAN) days;
5)
Feeder voltage; and
6)
The potential losses from a bushfire taking into account population, terrain, fuel loads and fuel types.
Table 5: Proposed implementation strategy costing for 33kV, 19kV & 11kV reclosers
2015/16
Replace 30 per annum nonSCADA 33kV, 19kV, 7.6kV &
11kV reclosers with SCADA
Controlled Reclosers
$3.6m
2016/17
$3.6m
2017/18
$3.6m
2018/19
$3.6m
2019/20
$3.6m
14
Recommended Bushfire Risk Reduction Strategies
5.2.
Undergrounding or insulating LV, 11kV and 33kV Lines
5.2.1.
Description
Bare overhead conductor is the standard form of construction for high voltage distribution lines. However, as the
line is bare, it is vulnerable to ‘environmental’ faults such as vegetation, animals and insulation pollution. When
faults occur, a fire may start due to direct contact, arcing or from the by-products of flashover.
Re-building lines underground provides significant benefits, including elimination of fire start risk, but at relatively
high cost. A highly targeted program of undergrounding is typically implemented to reduce the risk of fire starts
at a reasonable cost.
Alternatively, bare conductors can be replaced with insulated conductors that reduce fire start risk at a lower
cost to undergrounding.
5.2.2.
Background
The SA Power Networks distribution network comprises 66 kV and 33 kV sub transmission lines, three phase
and single phase 11kV distribution lines, 19kV SWER lines and low voltage (LV) lines. As mentioned in Section
3.1, 33kV power lines start more fires per 1,000kms of line than all of the other voltages.
Insulated conductor technology is an overhead construction but the conductors are insulated with a covering
and supported in a bundle or spaced apart. There are a number of variants and the most popular are Aerial
Bundled Conductor (ABC), Covered Conductor Thick (CCT) and Hendrix conductor. ABC is made up of tightly
bundled insulated and screened conductors, while CCT is a conductor around which is applied a thick insulating
material but without a screen. The Hendrix system is made up of 3 insulated conductors in a closed
triangular/delta configuration, supported by a catenary wire.
The Hendrix system appears to provide the most satisfactory alternative to large scale conversion of bare
conductor to an insulated construction. By using a support wire under tension and with the phase conductors
suspended below, the Hendrix system allows the construction of longer spans than ABC. Hendrix systems are
not as aesthetically pleasing as undergrounding, but are generally lower in cost.
Undergrounding of overhead 33kV and 11kV power lines also effectively eliminates bushfire start risk.
Undergrounding avoids the costs that are still incurred to keep growing vegetation from rubbing against
overhead insulated conductor. Also, feedback from customer surveys confirms that customers are often willing
to pay for targeted undergrounding of powerlines when there are joint visual amenity and fire start risk reduction
benefits.
5.2.3.
Industry Practice
Australian DNSPs are typically undergrounding in circumstances such as:
New residential estates;
Where there is a financial benefit to do so;
Joint utility/local council funded undergrounding schemes; and
Projects initiated by individuals or developers who contribute towards the costs.
15
Recommended Bushfire Risk Reduction Strategies
Recommendation 27 of the VBRC related to the progressive replacement of distribution feeders with
underground cable, ABC, or other technology that delivers greatly reduced bushfire risk. The PLBSTF
recommended implementation of this recommendation by the targeted replacement of distribution power lines
with underground or insulated overhead cable.
5.2.4.
Route Lengths and Costs
The following table identifies the route lengths of overhead conductors in the SA Power Networks distribution
network and approximate costs of reconstruction of bare lines with alternative conductors.
Table 6: Route Lengths and Costs for New 11 and 33kV Construction
VOLTAGE
HBFRA Route km
MBFRA Route km
11kV
7079
5902
33kV
931
2575
CONSTRUCTION TYPE
COSTS per route km7
Undergrounding
$260k to $650k
ABC/CCT
$220k to $320k
Hendrix
$90k to $170k Average $120k
5.2.5.
Discussion and implementation strategy
Broad scale undergrounding of overhead HV lines is generally an unrealistic option due to the high cost.
However targeted undergrounding to avoid vegetation clearance or to provide a robust all-weather supply to
8
Bushfire Safer Precincts (BSP) should be considered on a case-by-case basis.
Insulated conductor is vulnerable to the effects of bushfires and hence undergrounding lines is preferred for
supply to BSPs. However, should SA Power Networks consider broad scale conversion of bare lines in HBFRA
in order to lower fire start risk, an insulated conductor system may prove more cost effective.
A proposed implementation strategy for undergrounding lines to BSPs is shown in Table 7. Note that
undergrounding of other parts of the network for aesthetic and fire start risk reduction reasons is included in
other parts of SA Power Networks’ Reset Submission.
7
From PLBSTF Final Report
8
http://www.cfs.sa.gov.au/site/prepare_for_bushfire/know_your_area/bushfire_safer_places.jsp
16
Recommended Bushfire Risk Reduction Strategies
The CFS has identified 65 BSPs in high bushfire risk areas. Jacobs recommends that SA Power Networks
applies risk management principles to prioritise these sites.
The proposed implementation strategy shown in Table 7 covers undergrounding of lines to 12 BSP sites over a
5 year period.
Table 7: Proposed Implementation Strategy for 11kV and 33kV supply to BSPs
2015/16
Undergrounding of 11kV
and 33kV to BSPs
$5.7m
2016/17
$5.9m
2017/18
$3.8m
2018/19
$6.3m
2019/20
$4.9m
17
Recommended Bushfire Risk Reduction Strategies
5.3.
Increased Frequency of Asset Inspections
5.3.1.
Description
In complying with the Electricity Act and Distribution License requirements, SA Power Networks submits a
Safety, Reliability, Maintenance and Technical Management Plan (SRMTMP) annually to the State
Government’s Office of the Technical Regulator (OTR).
Periodic asset inspections are an integral part of the SRMTMP.
5.3.2.
Background
All Australian DNSPs engage qualified asset inspectors to undertake routine asset inspections using visual and
various inspection equipment. Specific inspection procedures and training ensure a high quality of inspections.
SA Power Networks’ asset inspection period varies from 5 years for high corrosion zones to 10 years for low
corrosion zones. Whilst there is some HBFRA in high corrosion zones, the majority of H/MBFRA is located in
low corrosion zones. The typical period for detailed asset inspections is therefore 10 years.
To complement the inspection programme, a pre-bushfire season patrol is conducted for all assets in bushfire
risk areas, with specific focus on fire start issues. Evidence shows that these patrols are effective at finding
defects which develop after spring storms and vegetation which grows more rapidly than expected.
Figure 1 – Photo taken during pre-bushfire season aerial patrol programme
18
Recommended Bushfire Risk Reduction Strategies
5.3.3.
Industry Practice
Typical inspection regimes across Australia are time based with historical inspection regimes as per the
following table:
Distributor
Historical Overhead assets Inspection
Frequency9
ActewAGL
4.5 – 5 years
Endeavour Energy
4.5 years
Jemena
5 years
TransGrid
4 yearly
Powercor
5 yearly
SPI Ausnet
5 yearly
Essential Energy
4 yearly
The VBRC investigated the causes of the bushfire starts on 7 February 2009 in Victoria. Five of these bushfires
were confirmed as having started from electricity assets. In July 2010 the VBRC released its findings, eight of
which directly related to measures for preventing future bushfire starts from electricity assets. One of the
recommendations was that, based on the evidence that had been presented, Victorian utilities should move
from their existing 5 year inspection cycle to a 3 year inspection cycle. The Victorian Government then legislated
this requirement.
Jacobs suggests that the Victorian requirement establishes a new industry standard, taking into account
historical inspection frequency.
Jacobs recommends that SA Power Networks:
-
5.3.4.
Initially increases the frequency of asset inspections to a maximum of every 5 years for HBFRA and
MBFRA;
Assess whether a further increase in frequency of asset inspections (e.g. to 3 years) is warranted for
these areas;
Gradually increases the frequency of asset inspections for all other areas to 5 years; and
Retains the annual pre-bushfire season patrols in their current form.
Effectiveness
Examination of fire start records indicate that many fire starts may be avoided over a 5 year period in H/MBFRA
with highly effective asset inspections.
9
SKM survey of Australian Distribution Network Service Providers August 2013
19
Recommended Bushfire Risk Reduction Strategies
5.3.5.
Costs
The costs associated with inspections vary according to the geographic location (metropolitan compared to
country), terrain, accessibility and type of construction. Also, the extent of asset condition detail recorded
during the inspection determines the time taken and thus cost.
Inspection costs can be in the order of $500 to $2,500 per route km depending on the density of assets along
the route. A reasonable estimate for rural and country asset inspections is $500 per route km.
5.3.6.
Discussion and implementation strategy
A reasonable implementation strategy would be as follows:
1) Increase the frequency of asset inspections to a maximum of every 5 years for HBFRA and MBFRA;
2) Gradually increase the frequency of asset inspections to every 5 years for all other areas;
3) Assess whether a further increase in frequency of asset inspections (e.g. to 3 years) is warranted.
The costing of this strategy is based on the difference in expenditure between the current regime and the
proposed regime.
Table 9: Proposed Implementation Strategy Costings for Increased Asset Inspections
2015/16
Increased
inspections
$2.3m
2016/17
$2.6m
2017/18
$2.7m
2018/19
$2.7m
2019/20
$2.7m
20
Recommended Bushfire Risk Reduction Strategies
5.4.
Thermographic Inspections in H/MBFRA
5.4.1.
Description
Thermographic inspections of overhead powerlines can assist in the identification of potential conductor and
joint faults.
Figure 2 – typical record of a hot joint inspection
Hot joints can arise in line conductors where a sleeve has been used to connect conductors, or in connections
to overhead lines (taps) and lug connections to equipment such as transformer bushings, switching and
protection devices.
The inspections use thermographic imaging devices that can record and display the temperature profile of a
power line component. Anomalies and variations can be easily identified and trigger levels or alarms can be set
to assist the operator.
5.4.2.
Background
Conductors and joints can fail due to corrosion or imperfect jointing practices. Imperfect joints have a higher
resistance to electricity flow. A good joint should be of similar resistance per unit length to the conductor to
which it is connected. At low loads, the temperature of an imperfect joint is low and the temperature rise in the
joint is small. As the current passing through the joint increases, the temperature of the joint increases due to
its higher resistance. As the power loss is proportional to the square of the current, high temperatures occur at
a poor joint under high load currents. Sections of corroded conductor are also affected in this manner.
At high loads or during the passage of fault currents, temperature of imperfect joints or corroded conductor
sections may become excessive, causing the conductor or joint to fail. Sparks can be created and molten metal
may fall to the ground from overhead power lines causing fire starts. Thermographic inspections undertaken
during high load periods can identify corroded conductors, poor joints and terminations.
21
Recommended Bushfire Risk Reduction Strategies
SA Power Networks carries out thermographic inspections as follows:
-
5.4.3.
66kV and 33kV assets at 2 and 3 yearly intervals respectively;
Greater metropolitan 7.6kV and 11kV lines every 2 years; and
Country 11kV & 7.6kV assets at 5 yearly intervals.
Industry Practice
Thermographic inspection is one of the tools used widely by Australian DNSPs.
5.4.4.
Costs
The annualised cost of thermographic inspections for SA Power Networks assets ranges from $0.3m to $0.45m
per annum, based on the current testing frequency.
Increasing the extent of thermographic inspections of rural 11kV & 7.6kV lines from main backbone segments
only to all line segments would increase the costs marginally.
5.4.5.
Discussion and implementation strategy
Examination of fire start records indicate that a significant number of fire starts may be avoided in H/MBFRA
with effective thermal inspections. For example, the defect on the LV switch in the installation in Appendix 2
would require the use of thermographic equipment to pinpoint its location. This fault would not have been
visible to the inspector who visited the site a few weeks earlier.
A reasonable implementation strategy may be as follows:
1) Undertake thermographic inspections in HBFRA for 11kV, 33kV and LV at five yearly intervals during
summer peak load periods.
2) Undertake thermographic inspections in MBFRA for 11kV, 33kV and LV at five yearly intervals during
summer peak load periods.
The costing of these options is based on the difference in expenditure between the current regime and the
proposed regime.
Table 10: Implementation Strategy Costings for Increased Thermographic Inspections
2015/16
Cost: MBFRA
and HBFRA
$0.5m
2016/17
$0.5m
2017/18
$0. 5m
2018/19
$0.5m
2019/20
$0.5m
22
Recommended Bushfire Risk Reduction Strategies
5.5.
Install Surge Arrestors
5.5.1.
Description
Electric power systems are exposed to unsafe overvoltages caused by lightning and switching surges. Such
over-voltages can damage insulation and equipment. To protect the equipment, and avoid either a catastrophic
failure or a weakening of the equipment, devices are installed to detect and discharge over-voltage surges to
earth.
Rod Air Gaps (RAG) and Current Limiting Arcing Horns (CLAH) are a low cost form of overvoltage protection
that have been used widely in SA Power Networks for many years. Rod Air Gaps are applied to high voltage
insulators and comprise usually three metal rods arranged to provide two air gaps between the high voltage
connection and earth. CLAHs are a series combination of a rod gap and a non-linear current limiting zinc oxide
resistor. Conduction to earth occurs during an overvoltage event of sufficient magnitude to break down the
insulation of the two air gaps in the case of Rod Air Gaps and the one air gap in the case of the CLAH device.
Surge arrestors (or arrestors) are more expensive than RAGs and CLAHs, but provide an effective and gap-free
form of overvoltage protection. As they have only been used by SA Power Networks since 2003, there are many
CLAHs and RAGs still in service. In recent years some of these devices have been replaced with Surge
Arrestors, but this has been on an opportunity basis only.
5.5.2.
Background
SA Power Networks’ historical practice was to install RAGs or CLAHs on 33kV, 19kV and 11kV power lines as
an economic overvoltage protection method.
While these devices are low cost, they suffer from a number of deficiencies:
-
-
5.5.3.
The accuracy and repeatability of voltage breakdown varies because the breakdown characteristic is
dependent on accurate setting of the rod gaps and varies with humidity and rain. This aspect means
that there may be failures of insulation and conductor burning due to poor overvoltage protection
performance of rod gaps;
Because the rods are un-insulated, there is the potential for animals, birds and airborne vegetation to
bridge the air gaps causing a flashover;
When the devices operate, there is a power frequency follow-through current that can cause sparks and
molten metal to drop, creating a fire start risk; and
Electromagnetic interference may be generated during a flashover.
Industry Practice
RAGs are rarely used by other Australian DNSPs due to their low accuracy in surge voltage suppression and
their vulnerability to bypassing (caused by animals and birds). A typical report form for this defect is shown in
Appendix 1. Most Australian DNSPs use surge arrestors for their power line overvoltage protection.
5.5.4.
Costs
The replacement of 33kV RAGs or CLAHs with surge arrestors costs about $4,670 per three phase set.
The replacement of 19kV RAGs or CLAHs with surge arrestors costs about $2,007 each.
23
Recommended Bushfire Risk Reduction Strategies
The replacement of 11kV RAGs or CLAH with surge arrestors costs about $3,755 per three phase set.
5.5.5.
Discussion and implementation strategy
Examination of SA Power Networks’ fire start records indicates that a significant number of fire starts in
H/MBFRA could have been prevented if RAGs had been replaced with surge arrestors – refer to Appendix 1.
The implementation strategy should use the results of fire consequence modelling to identify locations of highest
consequence. Feeders should then be prioritised on the basis of:
Which line voltages lead to the most fire starts;
Which feeders have the highest numbers of CLAHs or RAGs to replace; and
Where there is a history of fires starting due to bird interference with line hardware.
Table 11: Proposed Implementation Strategy Costings for Installing Surge Arrestors
2015/16
Replace targeted RAGs or
CLAHs with Surge
Arrestors in HBFRA
$2.4m
2016/17
$2.4m
2017/18
$2.4m
2018/19
$2.4m
2019/20
$2.4m
24
Recommended Bushfire Risk Reduction Strategies
5.6.
Ground Fault Neutralising Technology
5.6.1.
Description
Ground Fault Neutralising (GFN) or Reduced Earth Fault Current Limiting (REFCL) equipment is new
technology that has the potential to reduce the incidence of fire starts by high speed detection of earth faults in
three phase power systems and rapid reduction of earth fault currents.
Reducing earth fault currents and fast fault clearing time, reduces the energy into a fault. This reduced energy
lowers the possibility of arcing and hence the potential for ignition of combustible material at the fault site.
5.6.2.
Background
Most Australian DNSP networks utilise balanced three phase high voltage feeder networks that are supplied
from a star connected zone substation transformer with the neutral conductor connected to the mass of earth.
Earth faults can occur when the phase conductor is connected to earth via a range of events including contact
with vegetation, animals and insulation failure. When these events occur, the power system becomes
unbalanced and a current path to earth is initiated that can create extremely high currents typically of many
hundreds or thousands of amperes. The earth fault current is detected by protection systems that operate
circuit breakers or switches to disconnect the fault for safety.
GFN technology requires new equipment and control systems to be installed in zone substations. The GFN
controller monitors the power system and detects unbalanced earth fault. The GFN injects voltages and currents
that re-balances the power system and provides high speed earth fault current reduction.
5.6.3.
Industry Practice
GFN technology was initially developed in Europe to improve network reliability by eliminating protection
triggered disconnection due to earth faults. Normally, the earth fault detection would disconnect the feeder, thus
limiting the risk of any unsafe condition for equipment or people. The GFN permits the network to continue to
operate safely until the defect can be assessed and rectified by field staff. The earth fault reduction achieved by
GFN technology provides a tool to not only improve network reliability but also to reduce the incidence of fire
starts.
This technology is being used in New Zealand for reliability purposes and trial installations are underway in
Victoria following the PLBSTF recommendations to investigate new technology to mitigate bushfires.
For the GFN technology to function, the network cannot have any phase to ground connected loads. SA Power
Networks has some phase to earth connected distribution transformers and pole mounted star connected power
factor correction capacitor banks installed. Insulation of equipment and lines must be able to withstand full line
to line voltage on what is normally phase to earth insulation.
Distribution transformers, cables and overhead line insulators are generally designed for the increased voltage,
but equipment such as surge arrestors and substation voltage transformers must be checked and replaced if
under-rated. Fault finding is also problematic as standard line fault indicators will not function correctly and
there is little visible evidence of the earth fault location due to the reduced fault energy.
25
Recommended Bushfire Risk Reduction Strategies
5.6.4.
Efficiency
This technology is relatively new to Australia but results interstate suggest SA Power Networks should
investigate its application in South Australia.
The PLBSTF estimated that a 70% reduction of fires starts may be achieved. Tests conducted by Marxsen and
HRL Technology on a real electricity distribution network confirmed that when a live high voltage conductor falls
to the ground under worst case fire weather conditions, such as those experienced on Black Saturday 2009,
GFN technology can reduce the conductor-soil arcing in many circumstances to levels below that required to
start a fire.10
5.6.5.
Typical Costs
The installation cost of this technology varies depending on the amount of ancillary work required, but is in the
range $1 million to $6 million per zone substation.
Table 12: Typical Installation Costs for GFN technology
Substation Type
Small
<=2.5MVA
GFN approx. Installation cost per
Zone Substation Type
Medium 2.512.5MVA
$1.0m
Large
>12.5MVA
$2.5
$6m
Table 13 identifies the numbers and range of zone substation sizes and their associated bushfire risk area
location.
Table 13. SA Power Networks 11kV Substations.
Substation
Type
10
Small
<=2.5MVA
Medium 2.512.5MVA
Large
>12.5MVA
Total
HBFRA
12
30
7
49
MBFRA
52
44
2
98
NBFRA
5
29
83
117
Total
69
103
92
264
Marxsen (2014)
26
Recommended Bushfire Risk Reduction Strategies
5.6.6.
Discussion and Implementation Strategy
Currently SA Power Networks has no practical experience with the installation, operation or maintenance of
GFN technology. However GFN technology is said to “…reduce the fault current to very low levels…so that the
likelihood of ignition is negligible…” (PLBSTF p.47). Therefore, it is proposed that this technology be installed
in two zone substations to test the stated benefits before any proposal is developed to roll out to other zone
substations.
Other utilities are investigating this technology. Jemena/United Energy in Victoria has installed a unit at its
Frankston South substation, comprising of 10 x 22kV feeders (Holmes 2011).
A reasonable implementation strategy would be as follows:
1) Install a test rig in association with higher education establishment or contractor to assess fire start
under current earth fault conditions compared to GFN conditions;
2) Install zone substation trials with say 2 adjacent substations in HBFRA to assess the extent of network
conversion required and to gain operational experience;
3) Install GFN at targeted zone substations in HBFRA where the fire risk is deemed extreme (future reset
period).
Table 14: Proposed Implementation Strategy Costings for GFN Technology
2015/16
GFN test rig
2016/17
2018/19
2019/20
$1.0m
Trial Installations at 2 Large adjacent
substations in HBFRA
Total Cost
2017/18
$1.2m
$4.0m
$5.0m
$2.0m
$4.0m
$5.0m
$2.0m
27
Recommended Bushfire Risk Reduction Strategies
5.7.
Re-construct Metered Mains
5.7.1.
Description
‘Metered mains’ refers to the electricity infrastructure between the revenue meter and the customer’s
switchboard, where the switchboard is remote from the meter. Metered mains are typically found on SWER
lines, usually where multiple buildings or bore pumps owned by a single customer are supplied from a single
meter, or multiple meters if there are multiple tariffs.
An example of a metered mains installation is shown below:
Figure 3 – Typical metered mains installation. During routine inspection support poles and some
lines were found on the ground. These are evident in the foreground. The defective line was made
safe pending ownership clarification.
5.7.2.
Background
Metered mains were created to reduce the time taken for meter reading by co-locating all meters for a property
close to or adjacent to the road. Unfortunately, metered mains were constructed to various standards, the
ownership of the asset between the meter and the customer’s switchboard is unclear and the condition is often
poor due to lack of maintenance. Some installations use trees, railway iron or wooden poles to support the
overhead conductors.
28
Recommended Bushfire Risk Reduction Strategies
Metered mains present a public safety risk and bushfire start risk. Recently, SA Power Networks has
commenced a programme of formally recording the locations and condition of Metered Mains installations in
preparation for their resolution.
5.7.3.
Industry Practice
Good industry practice is to establish and allocate ownership of all electricity infrastructure assets. The
responsibility for safety, maintenance and replacement is then clear, as is the liability for damages in the event
of failure or fire start. There is a statutory obligation (e.g. Work Health and Safety Act 2012) for any person
owning or operating electrical infrastructure to take reasonable steps to ensure the infrastructure or installation
is safe and safely operated.
This issue is similar to the Essential Energy low voltage private line undergrounding incentive scheme, where
there is a distributor-funded incentive to underground low voltage private lines that have defects, vegetation
management or end-of- life issues.
5.7.4.
Implementation Strategy
There are an estimated 5,000 metered mains installations in HBFRA and MBFRA in South Australia.
Predominantly, they are supplied from SWER and located in rural areas.
There is limited valid data available for detailed scoping of this project. Consequently, a structured
implementation plan will need to be developed, comprising:
Identification of metered mains locations, asset details including number of poles, conductor spans and
asset condition;
Risk assessment and prioritisation of remedial work;
Implementing a program to upgrade, repair or relocate assets; and then
Identification and documentation of ownership including formal advice to customers.
Jacobs understands that:
SA Power Networks personnel have recently commenced recording details of Metered Mains installations,
including their current condition, so that an estimate can be made of the scope of works required to make
these installations safe. This work should be completed by the end of 2014;
When unsafe installations are found, they are being made safe until a final solution is implemented; and
SA Power Networks proposes to restore identified metered mains to sound operating condition before final
ownership is established. This should be discussed with the Office of the Technical Regulator in SA.
Based on an expectation that all installations will require SA Power Networks’ input, current estimates are that
around $6.6M per annum will be required to make the estimated 5,000 installations safe.
29
Recommended Bushfire Risk Reduction Strategies
Table 15: Proposed Implementation Strategy Costings for Reconstruction of Metered Mains
2015/16
Reconstruction
of metered
mains
$4.1m
2016/17
$8.2m
2017/18
$8.2m
2018/19
$8.2m
2019/20
$4.1m
30
Recommended Bushfire Risk Reduction Strategies
5.8.
Backup Protection
5.8.1.
Requirement
Backup protection is intended to operate when a system fault is not cleared by the main protection because of
failure or inability of the main protection to operate. Within the industry, backup protection is said to be
adequate when a credible HV fault on a feeder is cleared in less than two seconds when the frontline protection
device or fault breaking device fails.
Further, the National Electricity Rules in Chapter 5, S5.1.9 Protection systems and fault clearance times
requires that;
(c) Subject to clauses S5.1.9(k) and S5.1.9(l), a Network Service Provider must provide sufficient primary
protection systems and back-up protection systems (including breaker fail protection systems) to ensure that a
fault of any fault type anywhere on its transmission system or distribution system is automatically disconnected
in accordance with clause S5.1.9(e) or clause S5.1.9(f).
Clause S5.1.9 requires that;
(f) The fault clearance time of each breaker fail protection system or similar back-up protection system of a
Network Service Provider must be such that a short circuit fault of any fault type that is cleared in that time
would not damage any part of the power system (other than the faulted element) while the fault current is
flowing or being interrupted.
5.8.2.
Background
SA Power Networks has numerous locations in their network where backup protection does not meet the
adequacy criteria. They are most commonly found where HV lines and transformers are only protected by highside fuses. The longer the conductor and the smaller the size of conductor, the lower are the fault levels and
hence the more difficult it is for fuses to detect the expected range of faults.
Historically, SA Power Networks has relied on one set of protection for rural feeders based on the use of
hydraulic reclosers, as these reclosers have been reliable in the past. However, recent events (refer Appendix
3) have shown that they are not fail safe and many are reaching end-of-life with increasing failure rates.
On 30 April 2013 a bulldozer operator pushed a tree branch onto a SWER line resulting in 4 spans of conductor
on the ground. As the backup protection was inadequate, the conductor remained on the ground alive, with
workmen in close proximity. The fault was only cleared when the transformer supplying the SWER line failed
catastrophically.
By contrast, on 23 March 2013 a fault occurred at a substation. The primary protection failed and the substation
fault was instead adequately cleared by backup protection at the source of supply for that substation.
A conductor remaining on the ground alive increases the risk of starting a fire. As stated previously, at the
VBRC11 it was agreed that the probability of a fire starting from a downed conductor increases significantly if the
fault clearing device operates slowly and operates a number of times.
11
Transcript of Victorian Bushfires Royal Commission, Tuesday 17 November 2009, pp 11103-11106
31
Recommended Bushfire Risk Reduction Strategies
The recent increase in hydraulic recloser failure rate, combined with higher expectations of utility asset
performance following bushfire investigations in South Australia and Victoria, has increased the urgency for
ensuring back up protection is adequate.
5.8.3.
Industry Practice
Good industry practice, and the minimum requirement, requires compliance with the National Electricity Rules.
The practice of other DNSPs is to adequately protect their HV networks with primary and backup protection.
SA Power Networks must upgrade its network accordingly.
5.8.4.
Implementation Strategy
The most economical method of providing back up protection is the installation of electronic reclosers with
SCADA. Electronic reclosers operate with high speed and have an extensive range of protection settings and
capability that can be varied to suit the specific application.
Installation of these devices will reduce the risk that assets are inadequately protected against fault, hence
lowering fire start risk. As these devices will be remotely controlled, their protection can be reset to single shot
operation and switched off remotely if required.
It is estimated that the work to align the backup protection to industry standards will require a 10 year program
to complete. This program will need to be coordinated with the recloser installation proposed in Section 5.1.1 to
ensure that the programs are merged without duplication.
Table 16 provides an estimate of the per annum cost to complete the installation of SCADA reclosers to provide
backup protection for the HBFRA, over the 5 years of the 2015-2020 Reset submission.
Table 16: Proposed Implementation Costings for Backup Protection
2015/16
Backup
Protection
$2.9m
2016/17
$3.0m
2017/18
$3.4m
2018/19
$3.6m
2019/20
$5.6m
32
Recommended Bushfire Risk Reduction Strategies
6. Recommended Strategies for AER Submission
6.1.
Good Industry Practice
Jacobs considers it prudent for SA Power Networks to implement additional risk mitigation strategies as:
The VBRC found that the events of Black Saturday called for “material reduction in the risk of bushfire
caused by the failure of electrical assets”. A similar expectation is likely to apply within South Australia;
The subsequent PLBSTF identified a range of initiatives to reduce the likelihood of powerlines starting
bushfires. Some of these are applicable to the distribution network in South Australia and are likely to now
be considered as good industry practice within Australia; and
General community expectation is that bushfire starts from electricity network assets are preventable by the
network owner. Litigation against network owners has arisen from numerous bushfire events in Victoria and
Western Australia in recent years.
SA Power Networks must ensure that it complies not only with regulations, but also with good industry practice
that has evolved following the extreme interstate events to include:
-
Effective risk management processes;
-
Upgrading of obsolete equipment to modern construction;
-
The installation of modern remote controlled technology for control, fault detection & protection;
-
Efficient and effective asset inspection and monitoring procedures that trigger appropriate and timely
maintenance regimes; and
-
Trialling of new technology.
While SA Power Networks has the statutory ability to disconnect supply, disconnections can only be undertaken
when extreme conditions justify such action. SA Power Networks’ disconnection capability and processes
reduce, but by no means eliminate, the risk of fire starts from network assets. Further risk mitigation requires
on-going investment in network assets.
33
Recommended Bushfire Risk Reduction Strategies
6.2.
Detailed Strategy Analyses - Summary
6.2.1.
General
SA Power Networks requested that Jacobs use the network management experience and engineering
judgement of its project team to recommend a practical, cost-effective package of risk mitigation strategies
required for SA Power Networks to comply with current good industry practice.
Eight ‘Recommended’ strategies are summarised below, with estimated implementation costs for a five-year
period tabled in Section 6.3. These eight strategies and implementation options have been selected to target
the issues and areas of highest fire start risk, accommodate SA Power Network’s capability to execute and
provide optimum fire risk mitigation benefits at a modest cost.
SA Power Networks should apply risk management principles to assess the probability and consequence of fire
starts for each of its feeders in high bushfire risk areas. Typically,
-
The probability of a fire start for a particular feeder is influenced by the reliability history, fire start
history, length of line, frequency of fire bans, and voltage;
-
The consequence of a fire start is derived from the maximum probable loss from a fire (estimated using
bushfire attack levels and loss calculations based on historic fires).
These risk assessments produce a ‘feeder risk ranking’ which assists selection of the appropriate strategy and
priority for each feeder within a staged work program.
Jacobs notes that Victoria’s Powerline Bushfire Safety Program (PBSP) includes works valued at $750 million
over 10 years, including a commitment of $200 million to replace powerlines in ‘areas of the highest
consequence risk’. Planned works include insulated overhead powerlines, underground powerlines, and the
upgrade of reclosers.
6.2.2.
SCADA reclosers for 33kV, 19kV and 11kV
Progressive replacement of ageing and inflexible 33kV, 19kV and 11kV reclosers with modern SCADA devices
would allow SA Power Networks to operate in a manner consistent with current good industry practice.
Modern reclosers, with remote control and monitoring, improve operating safety by enabling remote
disconnection on extreme fire risk days or remote disabling of reclose operations.
The implementation strategy costs shown in Section 5.1 assume the capability of SA Power Networks to
upgrade ~35 reclosers per annum in total (covering 33kV, 19kV and 11kV).
6.2.3.
New LV, 11kV and 33kV construction
The targeted reconstruction of bare conductor by either placing it underground or rebuilding with an insulated
form in high-risk locations, based on fire risk consequence modelling, is considered to have the greatest
potential for fire start risk reduction. Placing conductor underground would also significantly improve the
robustness of supply to Bushfire Safer Precincts.
The implementation strategy costs shown in Section 5.2 are based on undergrounding of lines to 12 BSP sites
over a 5 year period.
34
Recommended Bushfire Risk Reduction Strategies
6.2.4.
Asset inspection frequency
The frequency of SA Power Networks’ asset inspections is less than other DNSPs.
Jacobs recommends that SA Power Networks:
-
Initially increases the frequency of asset inspections to every 5 years (maximum) for HBFRA and
MBFRA;
Assesses whether a further increase in frequency of asset inspections (e.g. to 3 years) is warranted for
these areas;
Gradually increases the frequency of asset inspections for all other areas to 5 years; and
Retains the annual pre-bushfire season patrols in their current form.
The implementation costs detailed in Section 5.3 cover the additional inspection costs required to achieve that
frequency.
6.2.5.
Thermographic inspections
Effective thermographic inspections during periods of high load can improve the effectiveness of locating
conductor and joint defects in power lines.
An increased use of thermographic inspections by SA Power Networks is considered necessary to achieve
good industry practice.
The implementation strategy costs shown in Section 5.4 cover the additional inspection costs required to inspect
all line segments every 5 years in the HBFRA and MBFRA.
6.2.6.
Surge arrestors
Replacement of RAGs and CLAHs with surge arrestors can decrease the risk of fire starts by:
-
Preventing lightning weakening equipment insulation which then fails catastrophically on a high fire
danger day; and
The elimination of animals bridging of air gaps.
SA Power Networks’ use of rod gaps and CLAH is out of step with, and inferior to, other DNSPs that utilise
surge arrestors for overvoltage protection.
The implementation strategy costs shown in Section 5.5 cover replacement of 30% per annum of the existing
rod gaps in the HBFRA over a 5 year period.
6.2.7.
Ground fault neutralising technology
Although implementation of GFN technology for bushfire start prevention is in its infancy in Australia, it has
potential to reduce fire starts and it would be prudent for this technology to be trialled to:
-
Provide hard data for fire start reduction purposes; and
35
Recommended Bushfire Risk Reduction Strategies
-
Assess the installation and operational changes that would be required for roll out in SA.
The implementation strategy costs shown in Section 5.6 cover a test rig in Year 2 followed by trial installations
at two large substations during Years 3 & 4.
6.2.8.
Re-construct metered mains
There are approximately 5000 metered mains installations which have been built to various standards and are
in poor condition or unknown condition. They represent a public safety and bushfire start risk.
This project is considered necessary to resolve ownership issues and reduce public safety risk and fire start
risks for these assets.
The implementation strategy costs shown in Section 5.7 provide a preliminary estimate. A more detailed risk
assessment and scoping study will be required by SA Power Networks.
6.2.9.
Backup protection
The lack of adequate backup protection increases the risk of fire starts and risk to personal safety. SA Power
Networks needs to alter its line protection to re-align it with the National Electricity Rules.
36
Recommended Bushfire Risk Reduction Strategies
6.3.
Recommended Strategies and Estimated Costs
The eight recommended risk mitigation strategies and estimated costs are summarised in Table 17.
Table 17: Recommended Risk Reduction Strategies and Estimated Costs
Strategy
No.
1
Section and content
2015/16
2016/17
2017/18
2018/19
2019/20
5.1 Replace 33kV, 19kV and
11kV reclosers with SCADA
controlled modern units
$3.6m
$3.6m
$3.6m
$3.6m
$3.6m
$18.0m
2
5.2 Undergrounding or insulating
LV, 11kV and 33kV lines
$5.7m
$5.9m
$3.8m
$6.3m
$4.9m
$26.6m
3
5.3 Increase the frequency of
asset inspections
$2.3m
$2.6m
$2.7m
$2.7m
$2.7m
$13.0m
4
5.4 Extend and increase the
frequency of thermographic asset
inspections
$0.5m
$0.5m
$0.5m
$0.5m
$0.5m
$2.5m
5
5.5 Replace rod air gaps and
current limiting arcing horns with
Surge Arrestors
$2.4m
$2.4m
$2.4m
$2.4m
$2.4m
$12.0m
6
5.6 Undertake field simulation,
testing and trial installation of
Ground Fault Neutralisation
Technology
$1.0m
$4.0m
$5.0m
$2.0m
$12.0m
7
5.7 Reconstruct metered mains
$4.1m
$8.2m
$8.2m
$8.2m
$4.1m
$32.8
8
5.8 Backup protection
$2.9m
$3.0m
$3.4m
$3.6m
$5.6m
$18.5m
$21.5m
$27.2m
$28.6m
$32.3m
$25.8m
$135.6m
Totals
Total
37
Recommended Bushfire Risk Reduction Strategies
7. References
Marxsen,T., Coldham, D., Czerwinski, A. (2012)
New Research on Bushfire Ignition From Rural Powerlines
Published in the magazine T&D, February/March 2012
Powerline Bushfire Safety Taskforce 2011, ‘Final Report’, ESV website, 30 September 2011, viewed on 5
December 2013,
http://www.esv.vic.gov.au/Portals/0/About%20ESV/Files/RoyalCommission/PBST%20final%20report%20.pdf
Prof. Holmes, G. (2011)
Independent Expert Report on Rapid Earth Fault Current Limiters
RMIT University, Report prepared for the Powerline Bushfire Safety Taskforce, 9 September 2011
Prof. Holmes, G. (2011)
Independent Expert Report on Automatic Circuit Reclosers (ACR) for Single Wire Earth Return (SWER)
distribution lines
RMIT University, Report prepared for the Powerline Bushfire Safety Taskforce, 15 September 2011
T&D Magazine Bushfire Ignition Mitigation (2012)
Automatic SWER Single Phase Recloser
Transmission and Distribution, February/March 2012
Marxsen Consulting (2014)
REFCL Trial: Ignition Tests
Report prepared for United Energy
38
Recommended Bushfire Risk Reduction Strategies
8. Appendix 1: SA Power Networks fire report - Rod Air Gaps
39
Recommended Bushfire Risk Reduction Strategies
9. Appendix 2: SA Power Networks fire report - hot joint
40
Recommended Bushfire Risk Reduction Strategies
Appendix 2 (cont.) installation where fire occurred 19-Nov-2013
41
Recommended Bushfire Risk Reduction Strategies
10.
Attachment 1: Summary CV Information
The Jacobs project team comprised Phillip Webb, Terry Krieg and Greg Whicker.
Their summary CV information is included below:
42
Curriculum Vitae
Phillip Webb
EXECUTIVE ELECTRICAL ENGINEER
Summary of competencies
Phil has a Bachelor of Tech. - Electrical Engineering from (SAIT) and he is a Member of the Institution
of Engineers, Australia. With over 37 years experience in the Australian electricity supply industry, Phil
has specialist knowledge and understanding of National Electricity Market operation as well
understanding of Power System Security arrangements in the National Electricity Market. Some of his
achievements include Managing operational due diligence process for the transfer to NEMMCO for
Market and System Security functions in South Australia, System Control operational due diligence for
privatisation of the South Australian Electricity System. He was also responsible for the development
and implementation of quality systems for System Operation procedures for System Control functions
(Generation, Transmission and Distribution) in South Australia to achieve operating risk minimisation,
legal compliance and best practice operation.
Major project experience
QUALIFICATIONS
Managed operational due diligence process for the transfer to NEMMCO for Market and System
Security functions in South Australia.
Bachelor of Technology – Electrical
Engineering (SAIT), 1975
Managed System Control operational due diligence for privatisation of the South Australian Electricity
System.
CURRENT POSITION
Responsible for the development and implementation of quality systems for System Operation
procedures for System Control functions (Generation, Transmission and Distribution) in South
Australia to achieve operating risk minimisation, legal compliance and best practice operation.
Executive Electrical Engineer
EXPERTISE
Australian Electricity Transmission and
Distribution Networks and Equipment
Wind Farm Substation and collector
group assets, design, installation,
operation and maintenance
Power System Operational Control, HV
switching and HV Equipment Access
management
National Electricity Market operation
and Power System Security
Managed downsizing of System Operations Department to achieve real annual operating savings in
excess of $1.5M per annum.
Negotiated and managed the service provision for real time operational control and monitoring for
fast start generation and distribution system control and monitoring, providing improved returns to
shareholders.
Developed and negotiated operating protocols with customers requiring high voltage connections to
the ElectraNet SA Transmission system.
Recent project experience
Owners Engineer for the connection works for 8 Wind Farms.
Hallett Wind Farm SA,
Hallett Hill Wind Farm SA,
North Brown Hill Wind Farm SA,
The Bluff Wind Farm SA,
Waterloo Wind Farm SA,
Oaklands Hill Wind Farm Vic,
Macarthur Wind Farm Vic and;
Musselroe Wind Farm TAS.
Audit roles including: audits of SA Generators performance Standards for Australian Energy
Regulator and Network Performance Audits for ETSA Utilities Review roles for various utilities
including: Network Performance review post Cyclone Larry for Ergon, Review of ESCOSA Wind
Generation Licensing Statement of Principles and under frequency Load Shedding review for ESPIC,
Guaranteed Service Level Review and Transformer Failure Review for ETSA Utilities, Review of
Generation Trip events for Flinders Power.
Management of Operations Division responsible for the real time monitoring, control and operation of
the ElectraNet SA 275/132/66kV transmission system and the provision of control and monitoring
services to distribution and generation entities.
www.globalskm.com
PAGE 1
Curriculum Vitae
Terry Krieg
ASSOCIATE
Summary of competencies
A power electrical engineer with over 30 years industry and utility experience. Previously
a senior manager at a number of Australian infrastructure utilities in Queensland, South
Australia and the Northern Territory, Terry is a leader in the introduction of innovative
approaches to standardisation and design, asset management practices and condition
monitoring and has significant high voltage electrical plant experience in maintenance,
commissioning, testing and diagnostics of power networks plant.
QUALIFICATIONS
BE Electrical (First Class Honours)
Electrical Technicians Certificate
CURRENT POSITION
Senior Executive Engineer – Power
Networks
Chairman of CIGRE Study Committee B3 Substations
PROFESSIONAL MEMBERSHIPS
AND AFFILIATIONS
Fellow of Institute of Engineers Australia
PEng, APESMA
Registered Professional Engineer
Queensland (RPEQ)
Major projects include studies for major new infrastructure projects, the implementation of new
innovative standardised designs, new approaches to maintenance and on-line condition
monitoring and asset management of assets. He was introduced major improvements to asset
management practices within the power industry and has presented more than 25 engineering
and management papers and key note addresses on aspects of strategic asset management
to industry conferences in Australia, New Zealand, China, United States and Ireland.
Recent project experience
Murrindindi Bushfire Investigation, VICPOl, Vic, Australia
Alice Springs System Black Investigation, PAWC, Northern Territory, Australia
Due Diligence Assessment 500kV Gas Turbine and Switchyard, Vietnam
BSI PAS 55 Certification Audit, Abu Dhabi, UAE
F-Factor Audit (Fire Start) , Australian Energy Regulator, Vic, Australia
S- factor Audit (Reliability Incentives) , SPAusnet, Vic, Australia
Asset Management audit for power transmission, Transgrid, NSW, Australia
Substation Life Assessment and Asset Management Audit, Horizon Power, WA, Australia
Review of Design Standards - Current State Assessment, SPAusnet, Australia
Current State Assessment of Substation Design Standards and processes, Western Power,
WA, Australia
BSI PAS 55 Gap Assessment, Electranet, South Australia
Endorsed assessor for BSI - PAS55, IAM
(UK)
Feasibility Study for establishment of coal gasification plant, Australia
Chairman of CIGRE Study Committee B3
(Substations)l
Adelaide Tram Power Studies, SA, Australia
Graduate Australian Institute of Company
Directors (AICD)
EXPERTISE
High Voltage Substations
Power engineering
Asset Management
Design Standardisation
Fault investigations
Review of Asset Management Capability, NT, Australia
Development of Earth Grid Asset Management Plan, SA Power Networks, SA, Australia
Referee/s
Hamish McCarter
Senior Manager Engineering, Electranet
McCarter.Hamish@electranet.com.au +61 8 8404 7136
Rainer Korte
Executive Manager Network Strategy and Regulatory Affairs, Electranet
Korte.Rainer@electranet.com.au +61 8 8404 7983
Perry Tonking
Maintenance Division Manager, Transco
peregrine.tonking@transco.ae +971 (2) 6494606
Ben Li
Engineering Design Standards Manager, SPAusnet
bin.li@sp-ausnet.com.au +61 3 9695 6671
www.globalskm.com
PAGE 1
Curriculum Vitae
Greg Whicker
Role
Project Manager, contract formation, contract administration and quality
assurance
Qualifications
Bachelor of Applied Science (Secondary Metallurgy), Adelaide University
Graduate Diploma in Management, University of South Australia
Fields of Special Compentence
Metallurgy for the power industry, particularly
metallurgical
and
non-destructive
testing
&
assessments of aging generating plant
Asset management systems and strategies for
generating plant and other power station assets
Career History
2002 to current
Jacobs (previously Sinclair Knight Merz)
Project Director of a wide range of power sector projects,
including regulatory compliance audits, performance
reviews, management system reviews and investigations,
including:
Review of network performance reporting and
network outage management systems for DNSP
Technical advice to Victorian Govt during Bushfires
Royal Commission
Review of network operations centre operations for
DNSP
Review of management systems, emergency
exercises and vegetation management systems for
bushfire risk management for DNSP
Technical advice on various power system operation
issues for TSNPs, network owners, regulatory bodies
and planners
Asset management reviews of transmission lines for
TSNP.
Project Manager of various power sector projects,
including:
Owner’s Engineer role (civil/structural) for several
Hallett Wind Farms, Mt Millar Wind Farm, Wattle Point
Wind Farm, Starfish Hill Wind Farm, Lake Bonney
Wind Farm.
1993 to 2001
TXU, Optima Energy, ETSA
Asset Manager Torrens-Torrens Island Power Station
Accountable for providing asset management, risk
management and environmental management services for
Torrens Island Power Station.
Managed a group of specialists responsible for:
Setting and monitoring engineering, technical and
environmental
standards for Torrens Island
generating assets to ensure plant integrity, optimised
maintenance regimes, compliance with statutory
requirements and matching of plant capability to the
needs of the national electricity market
Scoping and managing the establishment and
execution of plant modification & refurbishment works
undertaken by contract.
Developed and implemented a range of asset, risk
and environmental management systems, and
coordinated all due diligence issues associated with
the privatisation of the power station.
1991 to 1993
ETSA-Generation Technology & Services Department
Mechanical and Civil Manager / Chief Metallurgist
Managed mechanical & civil engineering, metallurgy
and
draughting
specialists supporting
power
generation and coal mining within ETSA, providing
project management, contract management, contract
administration,
procurement
services
and
metallurgical services.
1970 to 1991
ETSA
Chief Metallurgist/Metallurgist
Due diligence review of a gas fired power station
Audit of asset management for a diesel generator
power station
CURRICULUM VITAE
Greg Whicker