2014 Reliability Plan. Annual Planning Report

Transcription

1 Annual Planning Report

2 2

3 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 FIGURE HISTORIC COMPARISON - SAIFI & SAIDI Yr Avg ('09-'11) SAIFI Yr Avg ('09-'11) SAIDI Fundamental in Hydro Ottawa s approach to system Storm Related Defective Equipment Loss of Supply Other 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. 3

4 4 Contents Executive Summary... 3 Contents Background Definitions Performance Key Measures System Targets SAIDI & SAIFI FEMI System Reliability Performance & Analysis Historical System Reliability Performance Measures Power Quality, Voltage and Waveform Performance Measures Reliability Analysis System Reliability Analysis Loss of Supply Defective Equipment Adverse Weather Major Event Days Worst Feeder Analysis Reliability Improvement Initiatives System Automation SCADA & Communications SCADA Communication Infrastructure Distribution Automation Automation Plans South Nepean Automation Plan East 28kV system West 28kV system kV Sub- transmission Automation Other Automation Plans Substation Automation... 27

5 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. 5

6 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: 6 Feeders Experiencing Multiple Sustained Interruptions (FEMI n ) 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. FEMI 10 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.

7 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 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. FIGURE HISTORICAL SAIDI & SAIFI SAIFI Yearly SAIDI excl LOS Yearly SAIFI excl LOS SAIDI Yearly SAIDI due to LOS Yearly SAIFI due to LOS 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. Metric TABLE SYSTEM RELIABILITY METRICS ERM Target Annual SAIFI < Yr Average SAIFI < Annual SAIDI < Yr Average SAIDI < FEMI Customer Interruption due to Storms 150% above 3-year average Customer Interruption due to Defective Equipment 130% above average 7

8 2.2 System Targets 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 FEMI 10 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 SAIDI, SAIFI & FEMI 10 TARGETS Metric / Indicator ERM Targets Quarterly YTD Duration of planned and unplanned interruptions (SAIDI) < 1.0 < 1.5 Frequency of planned and unplanned interruptions < 1.0 < 1.5 (SAIFI) SAIDI 3 year moving average < 1.5 < 1.5 SAIFI 3 year moving average < 1.0 < 1.0 FEMI

9 2.3 System Reliability Performance & Analysis Historical System Reliability Performance Measures Since 2009 the frequency of outages has been steadily increasing, peaking in 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. FIGURE HISTORIC SYSTEM SAIFI & SAIDI SAIFI 1.50 SAIDI Yearly SAIDI or SAIFI due to LoS 3-Year Average SAIDI or SAIFI excl LoS Yearly SAIDI or SAIFI excl LoS 3-year SAIDI Average incl LOS TABLE SYSTEM RELIABILITY PERFORMANCE ERM Target Yr Avg. SAIFI including LoS < Yr Avg. SAIFI excluding LoS N/A Yr Avg. SAIDI including LoS < Yr Avg. SAIDI excluding LoS N/A Yr Avg. CAIDI < FEMI 10 excluding LoS & Unplanned Outages

10 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 FEMI 10 Number of Circuits Experiencing 10 or More Interruptions TW22 TD12 TD01 BECKF2 8F1 7F4 77M6 624F6 249F2 TW22 TD14 BECKF2 8F1 7F4 77M1 249F2 TW22 TR09 TD01 TB06 MWDF2 8F1 7F4 77M6 77M2 624F6 249F2 249F1 TH11 TD14 TD06 TD01 TB15 TB06 7F4 77M6 624F6 49F6 249F2 249F1 190F5 TW22 TD05 TD01 TB06 MWDF3 BECKF2 ALXF3 8F1 7F4 77M6 624F6 249F2 249F FIGURE FEMI CIRCUITS SAIFI & SAIDI BY PRIMARY CAUSE 2% 2% 6% 8% SAIFI 2% 10% 13% 5% 21% SAIDI 2% 1% 26% 2% 21% 34% 5% 2% 11% 27% 0% 10 Adverse Environment Adverse Weather Defective Equipment Foreign Interference Human Element Lightning Loss of Supply Scheduled Outage Tree Contacts

11 2.4 Power Quality, Voltage and Waveform Performance Measures F IGURE P OWER QUALITY EVENTS ITIC CURVE Prohibited Region No Interruption 0.8 Region No Damage Region Time (seconds) 100 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. T ABLE PROHIBITED REGION EVENTS Date 16/03/ /04/2013 Site Cause RMS Voltage (PU) Duration (s) Casselman Loebs King Edward T1-Q King Edward T2-Z Hawthorne 48M4 Unknown Hydro One switching Hydro One switching Unknown cause Hydro One Hawthorne 48M3 Unknown cause Hydro One /07/2013 Albion T2-Y Hydro One Switching /09/2013 Marchwood T1 Unknown cause /10/2013 Lisgar T1-J Feeder fault Lisgar T2-Y Feeder fault /11/2013 Slater T2-J2 Hydro One switching /12/2013 South March A9M4 Unknown cause Hydro One /12/2013 Casselman Loebs Unknown /12/2013 Hawthorne 48M5 Unknown cause Hydro One /12/2013 Hawthorne 48M3 Hydro One switching Hawthorne 48M4 Hydro One switching Hawthorne 48M5 Hydro One switching /05/2013 RMS Voltage Magnitude (PU) Hydro Ottawa endeavours to operate the voltage in the distribution system in accordance to CSA CAN3-C 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. 11

12 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. 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 FIGURE SAIFI BY PRIMARY CAUSE 6% 0% 6% 10% 7% 8% 11% 8% 27% 17% FIGURE SAIDI BY PRIMARY CAUSE 3% 1% 2% 7% 14% 2% 19% 9% 11% 32% 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 12 Unknown/Other Loss of Supply Lightning Adverse Weather Human Element Scheduled Outage Tree Contacts Defective Equipment Adverse Environment Foreign Interference Foreign Interference Customer interruptions beyond the control of the distributor, such as animals, vehicles, digins, vandalism, sabotage, and foreign objects *Definitions from OEB s Electricity Reporting & Record Keeping Requirements, March 7, 2014

13 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 Collectively, Defective Equipment and weather related outages account for 60% of the 2013 SAIFI score and 71% of the SAIDI score. FIGURE SAIFI BY PRIMARY CAUSE COMPARED TO AVERAGE SAIFI SAIDI Yr Avg ('10-'12) Scheduled Outage (27%) Tree Contacts (55%) Lightning (131%) Defective Equipment(26%) Human Element (54%) Foreign Interference (15%) FIGURE SAIDI BY PRIMARY CAUSE COMPARED TO AVERAGE Unknown /Other (44%) Loss of Supply (103%) Adverse Weather (55%) Adverse Environment (129%) Unknown/Other (55%) Loss of Supply (152%) Tree Contacts (9%) Adverse Weather (41%) Adverse Environment (148%) Foreign Interference (9%) Yr Avg ('10-'12) 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 13

14 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 CONTRIBUTION TO LOSS OF SUPPLY SAIDI BY CIRCUIT 3% 1% SAIFI 0% 2% 14% 0% 0% 2% SAIDI 1% 31% 80% 8% 57% 1% Beckwith BECKF2 (27.6kV) A9M3 (44kV) Greenland GNLF2 (8kV) 72A3RM (115kV) Carp CARPF3 (8kV) C7BM (115kV) 62M2 (44kV) 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 CONTRIBUTION TO LOSS OF SUPPLY SAIFI & SAIDI BY SECONDARY CAUSE 31% SAIFI 14% 2% 29% 5% SAIDI 9% 53% 57% 14 Adverse Weather Defective Equipment Unknown / Other Lightning

15 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 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 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 DEFECTIVE EQUIPMENT SAIFI & SAIDI BY ASSET SAIFI SAIDI FIGURE DEFECTIVE EQUIPMENT SAIFI & SAIDI BY ASSET 0% 7% 0% 12% 16% 12% SAIFI 0% 0% 0% 2% 16% 4% 14% 9% 0% 6% 0% 1% 4% 7% 14% 17% SAIDI 0% 4% 2% 0% 1% 12% 6% 4% 30% 0% 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 15

16 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. 16 F IGURE TO49 B REAKER FAILURE

17 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 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 19 th. 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 STORM RELATED OUTAGES CONTRIBUTION TO SAIFI & SAIDI SAIFI SAIDI FIGURE STORM RELATED OUTAGES CONTRIBUTION TO SAIFI & SAIDI SAIFI 4% SAIDI 24% 23% 36% 60% 53% Tree Contacts Lightning Adverse Weather 17

18 3.2 Major Event Days Hydro Ottawa follows the Beta Method outlined in section 4.5 of IEEE Standard IEEE Guide for Electric Power Distribution Reliability Indices to determine Major Event Days. TABLE MAJOR EVENT DAYS Standard defines a Major Event Day as: A day in which the daily system SAIDI exceeds a threshold value, T MED. 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 T MED 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. Year Number Date Primary Cause April 24 th June 8 th July 17 th July 18 th May 4 th July 23 rd July 19 th Aug 22 nd Adverse Weather Adverse Weather Adverse Weather Loss of Supply Defective Equipment Adverse Weather & Loss of Supply 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 T MED was calculated based on the performance of 2008 through The 2013 T MED, calculated as per IEEE came to a daily SAIDI threshold of The following chart shows the daily system SAIDI graphically with the calculated threshold value, T MED. It can clearly be seen that only 2 days in 2013 exceeded the threshold: July 19 th and August 22 nd. On July 19 th, the Ottawa area experienced a lightning storm with high winds which caused a number of interruptions. On August 22 nd, the TO3UT breaker at the Overbrook Station failed causing an outage on two busses of 13kV station and at the 4kV Dagmar station. FIGURE DAILY SYSTEM SAIDI SAIDI tmed July 19 th August 22 nd

19 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 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 F4 Feeder Exposure Susceptible to animal and tree contacts 4 A9M3 Radial line Feeder exposure A new station transformer is being energized at Limebank in The 7F4 circuit will be split by the new 7F5 in Relocation of backyard O/H line in Stittsville. Construction to start in In 2013, poles and insulators in critical condition were replaced. Automation of two VBM switches at the intersection of Fallowfield and Shea in Construction of a 44kV line to tie A9M3 with 22M25 will commence in 2015 and conclude in A fully automated VBM will allow for quick supply transfer. New 44kV tie a VBM will be installed on Johnwoods & Hazeldean for further 19

20 Rank Feeder Issue 2013 Proposal sectionalizing under contingency. 5 TB06 Overhead switch failures Failed switches have been replaced, continue to monitor F6 Feeder exposure Susceptible to animal and tree contact caused interruptions 7 249F2 Feeder exposure Susceptible to animal and tree contacts 8 77M2 Largest interruption due to pole insulator failure 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. 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. Porcelain insulators are being replaced A new feeder purchased from Hydro One s Orleans TS will become available to support the area in 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 F2). 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 TOP 10 WORST FEEDERS SCORE VS. 3-YEAR TREND 20 Deteriorating Reliability Improving Reliability Trend Score 249F1 77M6 7F4 A9M3 TB06 624F6 249F2 77M2

21 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 21

22 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: 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) 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.

23 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 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. 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. 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 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 MHz 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 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. 23

24 FIGURE EXISTING FIBER NETWORK 24

25 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 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 These switches will be installed between 2013 and 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 F1 7F2 606F1 606F2 210F1 210F2 Existing Switch 2011 Installation 2012 Installation Future Installation FIGURE EXISTING AND PROPOSED LOCATIONS FOR REMOTELY OPERATED SWITCHES 25

26 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 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 kV 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 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 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 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.

27 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 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. 27

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