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TRANSCRIPT
2014 Reliability Plan Annual Planning Report
2014 Reliability Plan
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2014 Reliability Plan Annual Planning Report
Executive Summary Hydro Ottawa’s reliability performance in 2013 did not meet our expected targets. Interruption categories
such as defective equipment and adverse weather, or storm related have been progressively trending worse
and have exceeded the previous 3-year averages. Improvement will be needed in asset management
processes in order to prioritize end of life asset replacements. Maintenance, inspection and testing of
existing assets will continue to be essential to ensure equipment operates as expected and identify failures
before they occur. Consideration of new ways of operating to reduce system susceptibility to storm damage
and foreign interference is vital. In addition, investing in grid technologies will benefit reliability by reducing
restoration times and aid with predicting system faults.
Overall, since 2009 system
SAIFI has been steadily
increasing, due to the increase
of storms with severe wind
and rain as well as an increase
in equipment failures. Moving
forward, it is critical that
investment levels for
equipment replacement
increase in order to storm
harden the system and to get
ahead of the curve of aging
equipment.
Fundamental in Hydro
Ottawa’s approach to system
reliability is the
implementation of grid technologies. Ongoing targeted installation of automated devices is planned for the
foreseeable future to improve system reliability and operation. Currently, targeted programs are the East
44kV automation, which will deploy automatic restoration to this sub-transmission loop that supplies 3% of
Hydro Ottawa’s customers. In addition, automation plans are being deployed in the quickly growing South
Nepean/Barrhaven area, as well as targeted annual installation to address the Worst Performing Feeders.
Continued investment in the communication infrastructure will be essential to support current automation
plans while maintaining the flexibility to integrate the technologies of tomorrow.
FIGURE 0.1 - HISTORIC COMPARISON - SAIFI & SAIDI
0.41 0.53 0.44
0.41
0.68
0.17
0.31
0.30
0.42
0.28
0.30
0.50
3 Yr Avg
('09-'11)
2012 2013
SAIFI
0.41 0.54 0.45
0.310.33
0.04
0.440.35
0.54
0.66 0.420.65
3 Yr Avg
('09-'11)
2012 2013
SAIDI
Storm Related Defective Equipment Loss of Supply Other
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Contents Executive Summary .................................................................................................................................. 3
Contents .................................................................................................................................................. 4
1 Background ...................................................................................................................................... 5
1.1 Definitions ............................................................................................................................................ 6
2 Performance ..................................................................................................................................... 7
2.1 Key Measures ....................................................................................................................................... 7
2.2 System Targets ..................................................................................................................................... 8
2.2.1 SAIDI & SAIFI .................................................................................................................................... 8
2.2.2 FEMI10 ............................................................................................................................................... 8
2.3 System Reliability Performance & Analysis .......................................................................................... 9
2.3.1 Historical System Reliability Performance Measures ...................................................................... 9
2.4 Power Quality, Voltage and Waveform Performance Measures ....................................................... 11
3 Reliability Analysis .......................................................................................................................... 12
3.1 System Reliability Analysis ................................................................................................................. 12
3.1.1 Loss of Supply ................................................................................................................................. 14
3.1.2 Defective Equipment...................................................................................................................... 15
3.1.3 Adverse Weather ........................................................................................................................... 17
3.2 Major Event Days ............................................................................................................................... 18
3.3 2013 Worst Feeder Analysis ............................................................................................................... 19
3.4 Reliability Improvement Initiatives .................................................................................................... 21
4 System Automation ........................................................................................................................ 23
4.1 SCADA & Communications ................................................................................................................. 23
4.1.1 SCADA ............................................................................................................................................ 23
4.1.2 Communication Infrastructure ...................................................................................................... 23
4.2 Distribution Automation .................................................................................................................... 25
4.3 Automation Plans ............................................................................................................................... 25
4.3.1 South Nepean Automation Plan .................................................................................................... 25
4.3.2 East 28kV system ........................................................................................................................... 26
4.3.3 West 28kV system .......................................................................................................................... 26
4.3.4 44kV Sub- transmission Automation.............................................................................................. 26
4.3.5 Other Automation Plans ................................................................................................................ 26
4.4 Substation Automation ...................................................................................................................... 27
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1 Background
Hydro Ottawa continuously assesses the distribution systems service reliability. Where gaps are found, the
appropriate actions are identified to address these issues. Service reliability is integral to all work undertaken
as part of system planning and asset management. The Reliability Plan does not supersede the importance of
good Asset Management and System Capacity planning in the management of system reliability. Rather, it
provides a platform for thorough review of system reliability and identifies planned works which are designed
to directly impact system reliability.
Reliability driven projects are those which are designed to reduce outage frequency or duration regardless of
the cause. Such initiatives are almost exclusively automation projects, in general work considered as part of
the system reliability plan are:
� Deployment of remote sensors
� Deployment of remotely operable and autonomous devices
� Deployment of field devices to provide fault indications locally
� Supporting technologies to automation (i.e. communication & SCADA)
� Modifications to existing standards (i.e. animal guards)
System planning, asset management, and equipment maintenance also have direct impact on system
reliability – asset replacement prior to failure will prevent customer interruption and system planning can
reduce interruption duration through increased operability. While projects in these domains are primarily
discussed in the Asset Management, Maintenance, and System Capacity plans, their reliability impacts
discussed herein are one of the inputs to those planning processes.
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1.1 Definitions Interruption
Is a sustained loss of voltage/electrical supply on all phases to the customer’s supply point. Notwithstanding,
if the customer’s system is not able to accept electricity from Hydro Ottawa’s system, this is not considered
an outage. This does not include Partial Power (loss on some of the phases supplying a customer), or
sags/deformations, these are power quality events.
Loss of Supply
Is a primary cause classification which is utilized in the outage reporting and coding. This term indicates a
situation in which the system was ready to accept energy from the bulk system, and the providers are not
supplying. The term “Loss of Supply” therefore indicates a situation where Hydro Ottawa’s system is without
power for a reason that is beyond the control of Hydro Ottawa.
System Average Interruption Frequency Index (SAIFI)
This index is designed to give information about the average frequency of sustained interruptions per
customer over a predefined area. In words, the definition is:
This index is reported both including and excluding Loss of Supply (LoS). SAIFI including LoS provides
information as to the total interruptions which are seen by the ‘average’ customer. SAIFI excluding LoS
indicates the ‘average’ customer interruptions which are the result of causes under the direct control of
Hydro Ottawa.
System Average Interruption Duration Index (SAIDI)
Designed to provide information about the average time the customers are interrupted. In words, the
definition is:
This index is reported both including and excluding Loss of Supply (LoS). As with SAIFI, the SAIDI including LoS
provides information as to the total duration of interruptions which are seen by the ‘average’ customer
whereas SAIDI excluding LoS provides an indication as to the duration which the ‘average’ customer is
interrupted as the result of causes under the control of Hydro Ottawa.
Customer Average Interruption Duration Index (CAIDI)
CAIDI represents the average time required to restore power to the average customer per sustained outage.
In words, the definition is:
Feeders Experiencing Multiple Sustained Interruptions (FEMIn)
This index represents the number of feeders experiencing outages greater than or equal to value n, current
reporting is done for n=10. It is a customer centric measure as it provides an indication as to regions which
have seen high localized issues. FEMI10 is reported excluding Scheduled Outages as well as Loss of Supply, to
more accurately track regions seeing issues, as opposed to including regions seeing multiple outages due to
maintenance, repair and upgrade activities.
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2 Performance
2.1 Key Measures System reliability in 2013 continues to see
degrading performance. Loss of Supply,
Defective Equipment, and Adverse Weather
were the main contributors to the performance
of 2013.
Improvement will be needed in asset
management processes in order to prioritize
end of life asset replacements. Maintenance,
inspection and testing of existing assets will
continue to be essential to ensure equipment
operates as expected and identify failures
before they occur.
In addition, consideration of new
ways of operating to reduce
system susceptibility to storm
damage and foreign interference is
vital. Some of the initiatives
undertaken are a review of Hydro
Ottawa’s tree trimming program,
the use of animal guards, and
review of existing maintenance
programs.
Customer Interruption
due to Storms
150% above 3-year average
Customer
Interruption due to
Defective
Equipment
130%
above average
TABLE 2.1 - SYSTEM RELIABILITY METRICS
Metric ERM
Target
2011 2012 2013
Annual SAIFI < 1.5 1.68 1.81 1.53
3-Yr Average SAIFI < 1.0 1.41 1.63 1.67
Annual SAIDI < 1.5 2.60 1.64 1.68
3-Yr Average SAIDI < 1.5 1. 8 1.86 1.96
FEMI10 ≤ 12 12 13 13
FIGURE 1.1 - HISTORICAL SAIDI & SAIFI
1.05
1.05
2.43
1.31
1.64
0.45
0.31
0.16
0.33
0.04
0.82
0.77
1.40
1.13
1.36
0.33
0.63
0.28
0.68
0.17
09
10
11
12
13
Yearly SAIDI excl LOS Yearly SAIDI due to LOS
Yearly SAIFI excl LOS Yearly SAIFI due to LOS
SAIFI SAIDI
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2.2 System Targets 2.2.1 SAIDI & SAIFI
System reliability targets are set to flag where gaps exist and attention is required. Through review of
historical performance targets shown in Table 2.2 have been approved by Hydro Ottawa’s Board of Directors.
Asset management activities will continue to strive to maximize system availability and produce best in-class
system performance.
2.2.2 FEMI10 The goal of this metric is to identify those portions of the system which are experiencing high frequency of
interruption and highlight groups of customers which may in-turn be experiencing sub-par service reliability.
FEMI is a 12 month rolling window value and can be sampled at any month to view the past 12 month’s
performance. The performance target has been set based on historical performance, and can be seen in
Table 2.2.
TABLE 2.2 - 2013 SAIDI, SAIFI & FEMI10 TARGETS
Metric / Indicator ERM Targets
Quarterly YTD
Duration of planned and unplanned interruptions
(SAIDI)
< 1.0 < 1.5
Frequency of planned and unplanned interruptions
(SAIFI)
< 1.0 < 1.5
SAIDI – 3 year moving average < 1.5 < 1.5
SAIFI – 3 year moving average < 1.0 < 1.0
FEMI10 ≤ 12 ≤ 12
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2.3 System Reliability Performance & Analysis 2.3.1 Historical System Reliability Performance Measures
Since 2009 the frequency of outages has been steadily increasing, peaking in 2012. Despite year to year
variations, the frequency increases are associated primarily with a rise in Weather related outages, Defective
Equipment, and Foreign Interference. In 2013, the largest contributor to the frequency of interruptions was
due to Defective Equipment.
In 2013, the duration of outages slightly increased in comparison to 2012 but it was still lower than 2011
which was impacted heavily by three storms resulting in widespread outages. In 2013, the largest contributor
to the duration of interruptions was Defective Equipment, followed by Adverse Weather.
TABLE 2.3 - SYSTEM RELIABILITY PERFORMANCE
ERM
Target
2009 2010 2011 2012 2013
3 Yr Avg. SAIFI including LoS < 1 1.13 1.19 1.41 1.63 1.67
3 Yr Avg. SAIFI excluding LoS N/A 0.72 0.78 1 1.10 1.30
3 Yr Avg. SAIDI including LoS < 1.5 1.29 1.28 1.82 1.86 1.96
3 Yr Avg. SAIDI excluding LoS N/A 0.98 1.01 1.52 1.60 1.79
3 Yr Avg. CAIDI < 1.5 1.15 1.08 1.29 1.14 1.17
FEMI10 excluding LoS &
Unplanned Outages
≤ 12 9 7 12 13 13
FIGURE 2.2 - HISTORIC SYSTEM SAIFI & SAIDI
0.00
0.50
1.00
1.50
2.00
2.50
3.00
20
09
20
10
20
11
20
12
20
13
SA
IFI
0.00
0.50
1.00
1.50
2.00
2.50
3.00
20
09
20
10
20
11
20
12
20
13
SA
IDI
Yearly SAIDI or SAIFI due to LoS Yearly SAIDI or SAIFI excl LoS
3-Year Average SAIDI or SAIFI excl LoS 3-year SAIDI Average incl LOS
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The 2013 ERM targets were not met in 2013 for Annual SAIDI, 3 Year Average SAIDI and SAIFI as well as FEMI.
The contribution to the reliability performance in 2013 is discussed throughout this document, and the
missed targets cannot be attributed to one cause.
Feeders experiencing multiple interruptions were more widespread in 2013 with 13 feeders experiencing 10
or more interruptions. The primary contributors to the interruptions on these feeders are shown in Figure
2.4 and are: Defective Equipment, Foreign Interference and Adverse Weather. Six of the FEMI feeders align
with the Ten Worst Feeders (see section 3.3) and are thoroughly reviewed as part of that process for
potential improvement projects. The remaining 7 circuits will be investigated separately and any potential
improvements to reduce interruption impact identified.
FIGURE 2.3 – HISTORICAL SYSTEM FEMI10
FIGURE 2.4 - 2013 FEMI CIRCUITS SAIFI & SAIDI BY PRIMARY CAUSE
190F5249F1249F1
249F1249F2 249F2
249F2249F2
249F2
49F6
624F6
624F6
624F6
624F6
77M1
77M2
77M6
77M6
77M6
77M67F4
7F4
7F4
7F4
7F48F1
8F1
8F18F1
ALXF3BECKF2
BECKF2
BECKF2MWDF2MWDF3TB06
TB06
TB06TB15
TD01
TD01 TD01TD01TD05
TD06
TD12
TD14
TD14
TH11
TR09
TW22
TW22
TW22
TW22
0
2
4
6
8
10
12
14
2009 2010 2011 2012 2013
Nu
mb
er
of
Cir
cuit
s E
xp
eri
en
cin
g 1
0 o
r
Mo
re I
nte
rru
pti
on
s
2%
13%
34%
21%
2%
6%
2%
2%
8%10%
SAIFI
1%
26%
27%11%
0%
2%
5%
5%
21%
2%
SAIDI
Adverse Environment Adverse Weather Defective EquipmentForeign Interference Human Element LightningLoss of Supply Scheduled Outage Tree Contacts
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FIGURE 2.5 - 2013 POWER QUALITY EVENTS ITIC CURVE
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
0.001 0.01 0.1 1 10 100
RM
S V
olt
ag
e M
ag
nit
ud
e
(PU
)
Time (seconds)
2.4 Power Quality, Voltage and Waveform Performance Measures
Hydro Ottawa endeavours to operate the
voltage in the distribution system in
accordance to CSA CAN3-C235-83 in
steady state. By maintaining the voltage to
these standards, customers can expect all
of their devices, equipment and appliances
to operate as intended and expected
without damage or noticeable irritations
such as dimming or flickering lights.
Customers may however, on occasion,
experience voltage variations outside
these limits which Hydro Ottawa strives to
keep at a minimum.
Poor voltage regulation, outside ±6%, is
usually indicated by low voltage
complaints from customers. The target is to put corrective measures in place as soon as possible. The
increasing use of electronic devices is resulting in a progressive deterioration of waveform quality and it is
likely that further measures will need to be introduced and enforced in this area over the next decade.
The System Average RMS Variation Frequency Index (SARFI) is a measure of the average number of voltage
sags on the system. The ITIC curve, Figure 2.5, represents the 2013 RMS voltage variation events plotted
against the variation envelope which single phase modern devices can tolerate. Of the 2820 events recorded
in 2013, 16 fell within the prohibited region and are described in Table 2.4.
TABLE 2.4 - 2013 PROHIBITED REGION EVENTS
Date Site Cause RMS Voltage (PU) Duration (s)
16/03/2013 Casselman Loebs Unknown 1.104 1.642
12/04/2013 King Edward T1-Q Hydro One switching 1.117 0.867
King Edward T2-Z Hydro One switching 1.117 0.575
21/05/2013 Hawthorne 48M4 Unknown cause – Hydro One 1.120 97.000
Hawthorne 48M3 Unknown cause – Hydro One 1.120 97.000
18/07/2013 Albion T2-Y Hydro One Switching 1.110 24.380
20/09/2013 Marchwood T1 Unknown cause 1.101 2.833
16/10/2013 Lisgar T1-J Feeder fault 1.223 0.017
Lisgar T2-Y Feeder fault 1.224 0.017
15/11/2013 Slater T2-J2 Hydro One switching 1.120 9.575
05/12/2013 South March A9M4 Unknown cause – Hydro One 1.105 0.675
11/12/2013 Casselman Loebs Unknown 1.120 1.783
11/12/2013 Hawthorne 48M5 Unknown cause – Hydro One 1.108 90.390
18/12/2013 Hawthorne 48M3 Hydro One switching 1.114 1.350
Hawthorne 48M4 Hydro One switching 1.114 1.125
Hawthorne 48M5 Hydro One switching 1.113 0.900
No Damage Region
Prohibited Region
No Interruption
Region
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Cause of Interruption*
Unknown/Other Customer interruptions
with no apparent cause that contributed to
the outage
Scheduled Outage Customer interruptions
due to the disconnection at a selected time
for the purpose of construction or
preventive maintenance
Loss of Supply Customer interruptions due
to problems associated with assets owned
and/or operated by another party, and/or
in the bulk electricity supply system, based
upon ownership demarcation
Tree Contacts Customer interruptions
caused by faults resulting from tree contact
with energized circuits
Lightning Customer interruptions due to
lightning striking the distribution system,
resulting in an insulation breakdown
and/or flash-overs
Defective Equipment Customer
interruptions resulting from distributor
equipment failures due to deterioration
from age, incorrect maintenance, or
imminent failures detected by
maintenance
Adverse Weather Customer interruptions
resulting from rain, ice storms, snow,
winds, extreme temperatures, freezing
rain, frost, or other extreme weather
conditions (exclusive of Code 3 and Code 4
events)
Adverse Environment Customer
interruptions due to distributor equipment
being subject to abnormal environments,
such as salt spray, industrial
contamination, humidity, corrosion,
vibration, fire, or flooding
Human Element Customer interruptions
due to the interface of distributor staff
with the system
Foreign Interference Customer
interruptions beyond the control of the
distributor, such as animals, vehicles, dig-
ins, vandalism, sabotage, and foreign
objects
*Definitions from OEB’s Electricity
Reporting & Record Keeping Requirements,
March 7, 2014
Unknown/Other Scheduled Outage
Loss of Supply Tree Contacts
Lightning Defective Equipment
Adverse Weather Adverse Environment
Human Element Foreign Interference
3 Reliability Analysis
3.1 System Reliability Analysis System reliability has two primary components; frequency and
duration. Frequency relates most directly to the causal aspect of
system interruption whereas duration relates most directly to
operation of the system. System Average Interruption Frequency
Index (SAIFI) can be regarded as the “cause” and System Average
Interruption Duration Index (SAIDI) regarded as the “effect”.
Additional correlation on system interruptions based on the 10
Primary Causes outlined in the Electricity Reporting and Record
Keeping Requirements provide further statistical data that can be
used as indicators of system issues where remediation should be
undertaken to improve performance. Reliability scores are
evaluated for trending and patterns as seasonal and annual
variations are not always indicative of system deficiencies.
FIGURE 3.1 - SAIFI BY PRIMARY CAUSE
FIGURE 3.2 - SAIDI BY PRIMARY CAUSE
7%
6%
11%
8%
17%27%
8%
0%6%
10%
3%
14% 2%
9%
11%
32%
19%
1% 2%
7%
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System average interruption frequency and duration indexes have been broken out by primary cause shown
in the figures below. These indicate that the leading causes for outage frequency and duration are Defective
Equipment and weather related outages which include Lighting, Tree Contacts and Adverse Weather. Foreign
Interference is on an increasing trend and also had a notable impact to both SAIFI and SAIDI in 2013.
Collectively, Defective Equipment and weather related outages account for 60% of the 2013 SAIFI score and
71% of the SAIDI score.
FIGURE 3.3 – 2013 SAIFI BY PRIMARY CAUSE COMPARED TO ’10 -‘12 AVERAGE
FIGURE 3.4 - 2013 SAIDI BY PRIMARY CAUSE COMPARED TO ’10-‘12 AVERAGE
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
1.80
2.00
2009 2010 2011 2012 2013 3 Yr Avg
('10-'12)
SA
IFI
Unknown /Other (44%)
Loss of Supply (103%)
Adverse Weather (55%)
Adverse Environment (129%)
Scheduled Outage (27%)
Tree Contacts (55%)
Lightning (131%)
Defective Equipment(26%)
Human Element (54%)
Foreign Interference (15%)
0.00
0.50
1.00
1.50
2.00
2.50
3.00
2009 2010 2011 2012 2013 3 Yr Avg
('10-'12)
SA
IDI
Unknown/Other (55%)
Loss of Supply (152%)
Tree Contacts (9%)
Adverse Weather (41%)
Adverse Environment (148%)
Foreign Interference (9%)
Schedule Outage (29%)
Lightning (112%)
Defective Equipment (25%)
Human Element (66%)
Unknown/Other Scheduled Outage Loss of Supply Tree Contacts
Lightning Defective Equipment Adverse Weather Adverse Environment
Human Element Foreign Interference
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3.1.1 Loss of Supply In 2013, Loss of Supply was the third largest contributor to frequency of interruptions; however, it was a
small contributor to the duration of interruptions. There were 18 individual interruptions recorded due to the
loss of one of nine Hydro One components. The loss of the 27 kV circuit, BECKF2, contributed to 57% of the
Loss of Supply SAIDI but only affected 2% of SAIFI score. The loss of the 115 kV circuit, C7BM, contributed to
31% of the Loss of Supply SAIDI and 80 % of the SAIFI score, as can be seen in the figures below. The C7BM
has a large contribution to the reliability indices since it is a supply to many substations in the south.
FIGURE 3.5 - CONTRIBUTION TO LOSS OF SUPPLY SAIDI BY CIRCUIT
The majority of the Loss of Supply interruptions were caused by Adverse Weather conditions in the area;
however, the interruptions due to Defective Equipment had the largest impact to the Loss of Supply SAIDI as
shown in the following figure.
FIGURE 3.6 - CONTRIBUTION TO LOSS OF SUPPLY SAIFI & SAIDI BY SECONDARY CAUSE
2%0%
14%
80%
0%
3% 1% SAIFI
57%
1%
8%
31%
0%2% 1%
SAIDI
Beckwith BECKF2 (27.6kV) Carp CARPF3 (8kV)
A9M3 (44kV) C7BM (115kV)
Greenland GNLF2 (8kV) 62M2 (44kV)
72A3RM (115kV)
14%2%
53%
31%
SAIFI
9%
57%
29%
5%SAIDI
Adverse Weather Defective Equipment Unknown / Other Lightning
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Civil Structures Customer-Owned Fusing
O/H Conductor O/H Switchgear O/H XFRM
Pole Pole Attachment Secondary/Service
Station Equipment U/G Cable U/G Cable Attachement
U/G Switchgear U/G XFRM Unknown/Other
Vault Equipment
3.1.2 Defective Equipment The largest contributor to the duration and the frequency of customer interruptions in 2013 was Defective
Equipment. The customer impact of Defective Equipment outages has exhibited an increasing trend from
2009 to 2013. The top three contributors to Defective Equipment SAIFI in 2013 were: O/H Switchgear, U/G
Cable and Station Equipment. The top three contributors to Defective Equipment SAIDI is 2013 were: Station
Equipment, U/G Cable, and U/G Cable attachment. Collectively these four equipment classes account for
more than 60% of the Defective Equipment SAIFI and SAIDI in 2013. When compared to the trend of the last
few years there was a notable increase in the impact due to Station Equipment and O/H switchgear and a
notable decrease in the impact of UG/ Cable and Pole Attachment related interruptions.
FIGURE 3.7 - DEFECTIVE EQUIPMENT SAIFI & SAIDI BY ASSET
FIGURE 3.8 – 2013 DEFECTIVE EQUIPMENT SAIFI & SAIDI BY ASSET
0.00
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
2009 2010 2011 2012 2013
SA
IFI
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
2009 2010 2011 2012 2013
SA
IDI
0%
0%
0%2%
16% 4%
9%
6%
0%
14%16%
12%
0%7%
12%
0%
SAIFI
0%
2%0%
4%
12%1%
6%
4%
0%30%
17%
14%
1% 4%
7%
0%SAIDI
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O/H Switchgear – In 2013, there were 74 interruptions caused by the failure of overhead switchgear. This
includes failures to single and three-phase reclosers, fused cutouts, inline switches and solid blade switches.
Of the 74 interruptions, 4 failures to inline switches, 1 failure to a simple solid switch, 1 failure to a Vega
switch and 1 failure to a load break switch had the largest impact to both the Defective Equipment SAIDI and
SAIFI. There were no obvious trends in the causes for the failures found.
U/G Cable – Cable continues to appreciably contribute to annual customer interruptions. In 2013, there were
55 outages attributed to the failure of U/G cable. Of the 55 interruptions, 10 U/G cable failures had over 60%
impact to the U/G cable SAIFI and SAIDI. The main contributors to this category where single faults on trunk
lines affecting a large number of customers.
Station Equipment – In 2013, there were 21 Station Equipment related interruptions. The increase in the
contribution of station equipment failures is due primarily to the TO49 breaker failure at the indoor
Overbrook Station (See Figure 3.9). This breaker failure caused an outage to two buses at the Overbrook
Station (approximately half the 13kV station) and the 4kV Dagmar Station.
U/G Cable Attachment – In 2013, there were 21 interruptions attributed to the failure of U/G cable
attachments. The increase in contribution due to cable attachments is due primarily to two events: a
termination failure on the ALEXF3 feeder and a blown pothead on the TO3UT feeder which was partially
carrying TO2UT at the time of failure. These outages contributed to 40% of the U/G cable attachment SAIFI
and 71% of the U/G cable attachment SAIDI.
FIGURE 3.9 - TO49 BREAKER FAILURE
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3.1.3 Adverse Weather In 2013, Adverse Weather did not have a large contribution to the duration of interruptions and the
frequency of customer interruptions as it has been observed in previous years. However, when outages due
to Tree Contacts, Lightning and Adverse Weather are combined as “Storm Related Outages” they jointly have
the second largest contribution to the duration, and the largest contributor to frequency of customer
interruptions in 2013. The frequency of outages caused by storms increased significantly in 2013 when
compared to 2012, but the duration of these outages only had slight increased. In 2013, there were two
Major Event Days, one of them was caused by a storm involving lightning and high winds on July 19th
. Hydro
Ottawa continually tries to mitigate storm damage by including provisions in system design and identifying
assets for replacement that have degraded below the required design strength.
FIGURE 3.10 - STORM RELATED OUTAGES CONTRIBUTION TO SAIFI & SAIDI
FIGURE 3.11 – 2013 STORM RELATED OUTAGES CONTRIBUTION TO SAIFI & SAIDI
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
2009 2010 2011 2012 2013
SA
IFI
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
2009 2010 2011 2012 2013
SA
IDI
23%
53%
24%
SAIFI
60%
36%
4%SAIDI
Tree Contacts Lightning Adverse Weather
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3.2 Major Event Days Hydro Ottawa follows the “Beta Method” outlined in section 4.5 of IEEE Standard 1366-2003 “IEEE Guide for
Electric Power Distribution Reliability Indices” to determine Major Event Days.
TABLE 3.1 - MAJOR EVENT DAYS
Year Number Date Primary Cause
2011 4 April 24th
June 8th
July 17th
July 18th
Adverse Weather
Adverse Weather
Adverse Weather
2012 2 May 4th
July 23rd
Loss of Supply – Defective Equipment
Adverse Weather & Loss of Supply
2013 2 July 19th
Aug 22nd
Adverse Weather
Defective Equipment-
Dagmar/Overbrook
The daily system SAIDI threshold is calculated based on the
historical daily SAIDI values from the previous five years; this means
that the 2013 TMED was calculated based on the performance of
2008 through 2012. The 2013 TMED, calculated as per IEEE 1366-
2003 came to a daily SAIDI threshold of 0.114.
The following chart shows the daily system SAIDI graphically with
the calculated threshold value, TMED. It can clearly be seen that only
2 days in 2013 exceeded the threshold: July 19th
and August 22nd
.
On July 19th
, the Ottawa area experienced a lightning storm with
high winds which caused a number of interruptions. On August 22nd
,
the TO3UT breaker at the Overbrook Station failed causing an
outage on two busses of 13kV station and at the 4kV Dagmar
station.
FIGURE 3.12 - 2013 DAILY SYSTEM SAIDI
0
0.05
0.1
0.15
0.2
0.25
SAIDI tMed
Standard 1366-2003 defines a
Major Event Day as:
A day in which the daily system
SAIDI exceeds a threshold value,
TMED. For the purposes of
calculating daily system SAIDI,
any interruption that spans
multiple calendar days is
accrued to the day on which the
interruption began. Statistically,
days having a daily system SAIDI
greater than TMED are days on
which the energy delivery
system experienced stresses
beyond that normally expected
(such as severe weather).
Activities that occur on major
event days should be separately
analyzed and reported.
August 22nd
July 19th
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3.3 2013 Worst Feeder Analysis In 2011, a standard method to determine the “Worst Feeders” was defined. This method takes into
consideration the duration, frequency and number of sustained outages as well as the number of momentary
(duration < 1min) interruptions a feeder experiences.
Based on the Worst Feeder Methodology the 10 worst feeders were evaluated and potential improvements
to the feeders were proposed. The table below summarizes the findings from the detailed study completed
for each of the 10 feeders.
TABLE 3.2 - 2013 WORST FEEDER IMPROVEMENT PROPOSALS
Rank Feeder Issue 2013 Proposal
1 249F1 • Feeder Exposure
• Susceptible to animal and
tree contacts
• An additional feeder, 249F4, is being brought
out of the station to split the load on the
249F1. In particular, Findlay Creek will be
supplied from the new feeder limiting the
exposure from the existing circuitry north of
the neighbourhood.
• Spot trimming above and beyond the normal
vegetation management three year cycle was
performed late 2013 to reduce the probability
of tree contacts.
• Animal guards were installed on portions of the
circuit in 2013 to reduce the possibility of
animal contacts.
• A second station transformer is planned for
Leitrim in 2017, to provide redundancy, allow
for maintenance and additional capacity.
2 77M6 • Underground cable faults • More cable testing in this area to identify
potential for replacement or injection
• A new feeder purchased from Hydro One’s
Orleans TS will become available to support
the area in 2015.
3 7F4 • Feeder Exposure
• Susceptible to animal and
tree contacts
• A new station transformer is being energized at
Limebank in 2015.
• The 7F4 circuit will be split by the new 7F5 in
2015.
4 A9M3 • Radial line
• Feeder exposure
• Relocation of backyard O/H line in Stittsville.
Construction to start in 2014.
• In 2013, poles and insulators in critical
condition were replaced.
• Automation of two VBM switches at the
intersection of Fallowfield and Shea in 2013.
• Construction of a 44kV line to tie A9M3 with
22M25 will commence in 2015 and conclude in
2017. A fully automated VBM will allow for
quick supply transfer.
• New 44kV tie a VBM will be installed on
Johnwoods & Hazeldean for further
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Rank Feeder Issue 2013 Proposal
sectionalizing under contingency.
5 TB06 • Overhead switch failures • Failed switches have been replaced, continue
to monitor.
6 624F6 • Feeder exposure
• Susceptible to animal and
tree contact caused
interruptions
• Crews are encouraged to install animal guards
when completing construction on this circuit.
• The tree trimming crew worked in this area in
late 2013 as part of 3 year program.
7 249F2 • Feeder exposure
• Susceptible to animal and
tree contacts
• A second station transformer is planned for
Leitrim in 2017, to provide redundancy, allow
for maintenance and additional capacity.
• An additional feeder, 249F3, will egress once
the transformer is in place. This will allow the
load on 29F2 to be split.
8 77M2 • Largest interruption due
to pole insulator failure
• Porcelain insulators are being replaced
• A new feeder purchased from Hydro One’s
Orleans TS will become available to support
the area in 2015.
9 MWDF2 • • New second supply to the Marchwood DS
station will allow for load transfer at the
station without an interruption.
10 7F1 • Feeder exposure
• Susceptible to animal and
tree contacts
• A new station transformer is being energized in
2015 to allow for better load distribution and
less feeder exposure.
The Worst Feeder Methodology recommends tracking the worst feeders over a three year period to allow
time for the improvements to be seen. The following figure outlines the 10 worst feeders for 2013 and where
they sit in regards to Score versus Trend. Note that feeders that have a trend below 0.5 are seeing an
improvement in reliability (1 feeder in 2013 – 249F2). Moving forward, the feeders will need to be continually
tracked to determine whether the improvements made in the distribution have had an impact on improving
the feeder’s reliability, it is believed that there will be at least a three year lag in seeing the improvements on
the feeder – 1 year for the improvement to be implemented and the two following years to develop a new
trend.
FIGURE 3.13 - 2013 TOP 10 WORST FEEDERS SCORE VS. 3-YEAR TREND
0
0.5
1
0 0.5 1 1.5 2 2.5 3
Tre
nd
Score
249F1
77M6
7F4
A9M3
TB06
624F6
249F2
77M2
Imp
rov
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3.4 Reliability Improvement Initiatives In support of the HOL Customer Value and improving customer experience, Hydro Ottawa continually
implements projects to improve reliability in areas with known problems. The following works have been or
are planned to address the identified reliability issues.
Loss of Supply
The reliability and redundancy of system supply is continuously evaluated as part of the Capacity Planning
exercise. Where feasible, contingency plans are developed to expedite restoration and reduce the impact of
the loss of any one supply. As well, the installation of remotely operable devices are considered when
evaluating restoration and isolation scenarios to reduce the number of customers affected by a loss of supply
and to quickly be able to resupply the affected region.
Defective Equipment
U/G Cable – Replacement of end-of-life underground cable is an on-going program, which requires significant
investment. New cable condition information available from the U/G cable testing program started in late
2010, is being used to help identify end-of-life cable and prioritize these replacements to have maximum
impact. Also, the use of cable injection is being trialed to prolong the life of ageing cable, this technology may
allow areas of concern to be addressed more rapidly than traditional replacement.
U/G Switchgear – Replacement of end-of-life underground switchgear is an on-going program. In 2013, 5
switchgear were replaced. Switchgear are prioritized for replacement by condition and their criticality to
system operation. It is anticipated that by 2014 all 6-way gear that have become a non-stock item and are all
at end-of-life will be replaced.
O/H Switchgear – Overhead Switchgear are inspected as part of the Critical Switch program with the purpose
of maintain and inspecting switches that are deemed a higher priority. These switches are selected based on
the requirements to interrupt higher loads, supply many customers, or supply critical customers. The cyclic
three-year inspection program will ensure all areas (urban, rural and difficult access) will be visited, and aid in
detecting problems before they fail.
U/G Transformers – Currently, our underground transformer replacement program has been targeting the
removal of PCB containing units. Once all of the PCB transformers have been replaced a proactive
underground transformer replacement program will be evaluated to start targeting end-of-life units.
Station Equipment – Station transformers and switchgear/reclosers are being continually replaced based on
age and condition, as well monthly station maintenance and inspections take place to track and identify
potential issues with equipment and connections. The type and mechanism of station equipment failures will
continue to be monitored to identify any trends and possible solutions that could be implemented system
wide.
Adverse Weather
Continued enhancements are being made to the system to improve the withstand capabilities during storms
and to reduce the impact of individual outages. There are three initiatives/programs which address this need:
Pole Replacement – The condition of poles is evaluated on an ongoing basis. From the condition assessment a
review is conducted to determine the areas which are in the poorest condition so they can be targeted for
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planned replacement. By eliminating poles in poor condition and upgrading the attached hardware, the
ability of the system to operate through adverse weather without interruption is improved.
Vegetation Management – Updates to the vegetation management program currently underway are
anticipated to reduce tree contacts during wind storms. Changes to the program which are being
implemented include targeted tree trimming cycle and clearance distance from lines based on tree species
and their rate of growth. In addition ‘smart’ tree removals are being considered. ‘Smart’ removals would
target trees near overhead lines that either are near end of life and at risk of falling into the line or would
require excess trimming (i.e. trimming would be required too frequently or would negatively impact the
health of the tree) to maintain an appropriate clearance.
System Protection – Where appropriate, distribution reclosers are installed on the system. While these
reclosers will not completely eliminate outages, they do sectionalize the distribution circuit, minimizing the
number of customer interruptions for a given fault.
Worst Feeders
The worst feeder program is designed to address short term reliability issues in an immediate time-frame. All
work identified in the 2013 review will be carried out in the 2014 budget year, with targeted completion
before the beginning of storm season. In the Fall of 2014, identification and assessment of the worst feeders
will again be carried out and appropriate actions will be undertaken to improve performance of the identified
circuits.
System Activity Investigation Reporting Criteria
The Asset Planning Group has been engaged in producing System Activity Investigation Reports with the goal
of providing clarity into issues with the configuration and operation of the distribution system. System
activity investigation reports provide insight into the root cause of an event, identify issues with standard
process and procedures, and provide recommendations to mitigate re-occurring events. The Asset Planning
Group has developed a set of criteria to initiate system activity reports. These criteria will attempt to capture
events that can lead to corrective actions to further better the system and operating procedures.
Any of the following criteria can initiate a System Activity Investigation Report:
1- ≥ 1000 Customers and ≥ 1 Minute (Unplanned)
2- ≥ 8 Hours and ≥ 1 Customer (Unplanned)
3- Equipment/Protection mis-operation (HOL, HONI, or other).
4- Incidents where equipment failure, protection mis-operation, or system operation (i.e. switching)
have or are suspected to have caused or contributed to Health & Safety incidents (Public or
Employee) or property damage (i.e. catastrophic vault equipment failure).
5- Re-occurring incidents of supply quality falling outside tolerances for voltage, current, frequency and
harmonic distortion as specified in ECG0008, that are suspected to have originated from the
distribution system.
6- As circumstances require.
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4 System Automation Automation projects targeted to improve reliability performance cannot function without a strong
communication infrastructure. Ongoing investment over the next 20 years will be required to create a
communication network which is strong enough to support system automation plans, yet flexible enough to
integrate the quickly evolving technologies involved.
4.1 SCADA & Communications 4.1.1 SCADA
The automation class of assets is usually designated as
the SCADA (Supervisory Control and Data Acquisition)
system in substations and in distribution. Hydro
Ottawa Limited’s SCADA asset class system is used to
monitor and control station and distribution system
equipment.
SCADA supports system reliability by providing system
operators with real-time access to system status and
control, reducing time required to identify service disruptions, locate system faults, and operate the system
to restore customers. As more and more distribution assets are connected to the SCADA system, the
Operator’s situational awareness improves, resulting in a more focused and effective restoration effort.
The HOL SCADA system was installed in 2006 and has not received any significant updates since that time.
While the system has been maintained with vendor support, it is coming to the end of its useful service life.
Therefore, the Grid Technology group is planning on replacing the SCADA system during the Real Estate
Rationalization (starting 2015 with completion of installation in 2018) project as it will provide an opportune
time to transition to a new system.
4.1.2 Communication Infrastructure Communications are fundamental to all HOLs distribution automation plans. HOL communications
infrastructure includes a dark fiber network that Hydro Ottawa Ltd currently leases from Rogers
Communications Inc. (formerly Atria Networks), radio communications in both the licensed and unlicensed
900MHz spectrum, and phone based communication (both leased lines and cellular including LTE).
In early 2014, Hydro Ottawa Ltd. initiated a pilot project to deploy a small WiMAX network using the 1800 –
1830MHz band that has been reserved by Industry Canada for use in the management of the electricity
system. It is the goal of this project to evaluate the technology for use in distribution automation as well as
SCADA and metering applications. While the WiMAX network will not provide the throughput of 3G/LTE
systems, it does provide lower latency and a cost structure that will be more compatible with a utility
budgetary framework.
Hydro Ottawa continues to evaluate the best mix of these technologies to support increased communication
distribution and substation equipment in the future. Current challenges include the ongoing costs of leasing
fiber optic communications, as well as saturation of available radio communication primarily in the east area
of the city. As part of this evaluation, HOL has engaged a consulting firm to develop a telecommunications
master plan with their final report anticipated May 2014. With this plan, HOL intends to create a roadmap for
investment in communications infrastructure that will make efficient use of budget dollars as well as having a
maximum impact on device connectivity.
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FIGURE 4.1 - EXISTING FIBER NETWORK
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4.2 Distribution Automation Distribution automation supports improved reliability through reduced outage duration, and reduced
customer interruption. Outage duration is reduced through the addition of remotely operable device which
allow system operators to quickly restore customers following interruptions, as well as increased speed of
fault location through system monitoring. Customer interruptions are reduced by deploying autonomous
devices such as reclosers, which isolate faulted sections of the system and reduce the total customers
interrupted for a given fault.
4.3 Automation Plans 4.3.1 South Nepean Automation Plan
The South Nepean 28kV system is supplied by three 28kV stations, each with single source supplies.
Installation of automated switches will reduce outage duration. With rapid growth in this area, load transfers
are often required to maintain system loading within equipment ratings. With the addition of remotely
operable switches, load transfers can be executed faster in response to system loading.
There are 4 automated switches remaining to be installed to complete current plans in this area following
2012. These switches will be installed between 2013 and 2016. The switch locations are existing normal open
points between Fallowfield DS, Longfields DS and Limebank MS, or are strategic locations to allow for
sectionalizing of the feeders in south Nepean. The proposed locations for automated devices are shown in
Figure 4.2.
FIGURE 4.2 - EXISTING AND PROPOSED LOCATIONS FOR REMOTELY OPERATED SWITCHES
7F1
7F2
606F1
606F2
210F1
210F2
Existing Switch
2011 Installation
2012 Installation
Future Installation
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4.3.2 East 28kV system Hydro Ottawa’s East end 28kV system is modern, containing several remotely operable switching points.
Future automation projects in this area will focus on sustainment of existing automated switches and
additions as identified to improve functionality.
4.3.3 West 28kV system Planned addition of remotely operable devices on the west 28kV system is planned for 2013 and beyond.
Locations currently identified include installation of remotely operable tie switches between feeders to
reduce outage duration and increase speed at which circuits can be sectionalized in the Stittsville area.
4.3.4 44kV Sub- transmission Automation Hydro Ottawa 44kV sub transmission system supplies some large customers directly but is primarily the
supply network for a number of 8kV and a handful of 28kV substations. While interconnections exist, the
44kV system operate largely in isolation, with the East supplied from Hawthorne TS, South by Nepean TS and
West By South March TS.
East End 44kV
This project includes the plan to modernize and deploy automatic restoration on the 44kV loop in the east
end which is created by the 48M3, 48M4, and 48M5. These sub transmission circuits supply power to roughly
3% of Hydro Ottawa’s Customer base. This project includes the installation of station and distribution circuit
breakers as well as some minor system reconfiguration, and station reconfiguration.
This scheme will enable restoration of most customers without operator intervention and will eliminate the
need to dispatch crews. This scheme will improve supply reliability by eliminating sustained customer
interruptions at the existing 44/8kv stations for most sub transmission interruptions on the 44kV system.
West 44kV
The 44kV system in the west of the city is radial with predominately manually operated switches, many of
which are non-load break. Starting in 2012, deployment of remotely operable devices on this part of the
system is planned to improve operability and reliability.
2012 projects included the replacement of two existing manual non-load break switches on the A9M3 with
remotely operable switches. This will allow for sectionalizing and partial restoration without dispatching
crews. In 2013, three additional devices are planned to be installed on the A9M3 and A9M1 to further
improve operability of the system
4.3.5 Other Automation Plans CPP Padmount Control Improvement
Automated CPP padmount switchgear have had past issues with going out of calibration, resulting in failure
in remote operation. This project includes both engaging CPP to develop a solution as well as deploying the
solution in the field. This project is currently planned to be carried out in 2015.
FCI Program
Continuing on the success of the recent FCI trials of the last two years, 2010 saw the deployment of more
FCIs throughout the service area. In 2011 Hydro Ottawa has developed a comprehensive FCI deployment
plan. The plan will be broken into phases and will be implemented over the next several years. FCI indication
is an essential pillar in the effort to improve situational awareness and improve System Office’s ability to limit
the outage durations for customers on the large 27kV distribution systems. This technology is also valuable
as a key element in developing automated load restoration schemes.
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4.4 Substation Automation New station construction and station upgrades are incorporating the latest technologies and network
communication infrastructure. These stations will take advantage of the latest developments in
communication technology and in new electronic protection relaying, metering, and equipment monitoring.
These upgrades will also make use of newer and more advanced security features, thereby ensuring that the
enhanced connectivity does not come with enhanced risk. Along with this endeavour, existing substation
intelligent devices will be incorporated into the existing SCADA system to capture the real-time monitoring
data and providing this data to HOL’s Asset Management department through back office database links that
already exist. In 2010, all existing transformer oil analysis devices were connected to substation RTUs.
Substation automation work will be focused on the addition of online oil monitoring to aged transformers, at
a rate of 4 per year in 2012 and 2013, then decreasing to 2 per year beyond. In addition, work is planned for
continued deployment of Power Quality metering with the development of a real time link in 2014. With the
goal of reducing distribution losses a trial of closed loop line voltage control is planned to be initiated in 2014,
to enable lower operating voltage while maintaining customer voltage within the appropriate range. Another
significant benefit of the additional Power Quality metering will be the ability to capture waveform data from
system faults. This data can be processed using power quality software (PQView) in order to determine
approximate locations for faults (in conjunction with the FCI data). While there will be some additional effort
involved in calibrating this system, it is expected that it will eventually lead to a significant reduction in the
time spent investigating a fault and therefore reduce response time.
2014 Reliability Plan
28