A Practical and Cost Effective Cold Load Pickup Management Using Remote Control Presented to Western Protective Relay Conference 2014 Spokane, Washington, USA

Authored by Mukesh Nagpal, Gilles Delmée, Ahmad El-Khatib, Kelly Stich, Devinder Ghangass and Amit Bimbhra BC Hydro, BC, Canada

Abstract: Cold load pickup (CLPU) is the well-known problem defined as excessive inrush current drawn by loads when the distribution circuits are re-energized after extended outages. During extreme weather conditions, these currents can be high enough to appear as faults and/or overload resulting in blown fuses or breaker re-trips, further extending the outage duration. BC Hydro has several distribution stations within its system identified with CLPU issues. The purpose of this paper is to illustrate how BC Hydro has recently addressed complex CLPU issues by taking advantage of its enhanced remote control infrastructure. The paper characterizes the strategy that has been developed and implemented with focus on avoiding concession to protection settings. Practical examples of deployment at sites experiencing CLPU issues demonstrate the cost effectiveness of this solution with regards to the other alternatives available. The paper also provides records of successful load restoration under CLPU conditions including waveforms and restoration times highlighting the major operational improvements achieved. Keywords: Cold Pickup, Distribution Protection, Recloser, SCADA

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1. Introduction BC Hydro, the third largest electric utility in Canada, experiences peak demands from about 4.5 GW during summer light load conditions to more than 10 GW during cold spells in the winter seasons. Being a crown corporation, the utility has legislative obligations to supply all distribution customers within its supply area, including a large number of remote communities. It has about 1.8 million distribution customers, which account for about 85% of the total utility load demand. These customers are connected to more than 1300 distribution feeders emanating from 260 substations. Some 60 stations are built using wood-pole structures and are serving the remote rural communities. These wood-pole stations are typically supplied from a weak source comprising of single transmission circuit. They do not have a control room, DC supply or Supervisory Control and Data Acquisition (SCADA) for remote visibility and control (hereafter referred to as remote control). Distribution feeders are traditionally protected using inverse-time overcurrent protection, which is backed-up by the bus or transformer overcurrent protection. In the wood-pole stations, fuse on the distribution transformer high side backs-up the feeder protection. Inverse-time overcurrent protection is required to have the relay pickup (or fuse size) that must be sensitive enough to operate dependably for the minimum anticipated short circuit current and high enough to be secure for the maximum anticipated load current. Minimum short circuit currents are experienced when one or more of the source paths or transformers that supply the distribution substation are out-of-service. Maximum load current is often experienced when a feeder, a feeder section, or the entire distribution station is suddenly picked-up after an extended outage during the peak load. The pickup current for this condition can last from few minutes to longer than an hour and is commonly referred to as Cold Load Pickup (CLPU). During peak-demand periods, this current can sometime exceed the minimum anticipated short circuit current resulting in blown fuses or breaker re-trips and thereby extending the outage durations. Several distribution stations within BC Hydro system have experienced overcurrent protection misoperations due to CLPU; this includes blown fuses where the sensitivity requirements under weak source conditions conflicted with the anticipated maximum load currents experienced during CLPU. Historically, to deal with CLPU issues, BC Hydro was often forced to accept one of following options:   

Extended restoration time because Electricians and/or Power Line Technicians have to travel to sectionalize the feeder and allow load pickups in steps. Decreased protection sensitivity by raising overcurrent pickups or installing higher fuse sizes where viable. Capital expenditure to install protection relays, one or more circuit breakers, a control building, and related facilities, especially where a higher fuse rating is not acceptable but protection coordination using relaying solutions is achievable.

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

Significant capital expenditure to install power equipment to improve source strength or transfer load to another feeder originating from the same or different substation.

Picking up load in stages, splitting the feeder into small sections after the extended outage and then reconnecting them in steps on re-energization, is the most cost effective strategy but it can significantly add to the customer outage duration because of requirement for field staff to travel to the sectionalizing device locations along the feeder. Some BC Hydro distribution feeders are up to a few hundred kilometers long. Sectionalizing devices and rural distribution stations can sometimes become inaccessible after winter storms from road closures. At these locations, the outages from cold load pickups can then end up to be uncomfortably long. BC Hydro investigated means to remotely control distribution reclosers for the last several years though the motive was operational efficiency rather than addressing the cold load pickup concerns. Subsequent to this investigation, a standard design package was developed using wireless telecommunication technologies to achieve remote control for distribution reclosers. It is a low cost solution involving a standard design that requires no external infrastructure. Since the implementation is straightforward, BC Hydro now has a program to deploy this design change retroactively to all station reclosers1 over the next two to three years. As the remote control is becoming available, this paper demonstrates that System Operators are starting to have means to effectively manage cold load pickups especially for the remote locations. This paper reviews cold pickup outages involving three BC Hydro substations. The objective is to share the lessons learnt for operation/field personnel responses to restore the power after these outages as well as planning personnel strategy to prevent CLPU outages. One of the three stations is a small rural station, which has a single transformer protected by fuses on the high side. Prior to the reported outages, there was no remote control available for the station and field reclosers at this location. The station suffered unacceptably long outages (up to 17 hours) during winter seasons from cold pickups. After these outages, though station load growth forecast was minimal and within the transformer capacity, major equipment upgrades were planned with approved $10M funding to address the CLPU situations. However, the upgrades were ultimately withdrawn and remote control of the station and field reclosers were implemented instead to avoid the CLPU outages. At the two other locations presented in this paper, the CLPU issue is managed for one of the substations using an interim solution until the substation is decommissioned and for the other substation using remote control to restore load in less than one hour. In the past without remote control, restoration time during cold load used to be up to 10-12 hours long at that location. The paper begins with explanation of CLPU using data retrieved from BC Hydro’s Operational Information system. CLPU explanation is followed by brief background on BC Hydro’s methodology for determining inverse-time overcurrent pickup settings. Outage examples are then presented. Before concluding, the paper provides wireless 1

In this paper, a recloser installed outside of the substation on the distribution feeder is referred to as a field recloser and one installed inside the substation where the feeder originates is referred as a station recloser.

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SCADA architecture, which is key enabler for cost-effective remote control of the reclosers located in remote distribution substations and overhead feeders.

2. Cold Load Pickup Background Cold load pickup (CLPU) is the phenomenon where excessive currents are drawn by distribution loads when circuits are restored after extended outages. It is a generic term used to describe the overcurrent conditions caused by the combination of multiple factors during the restoration: magnetizing inrush, load inrush current, loss of diversity, and capacitor charging current. The magnitude of the phenomenon is strongly dependent of multiple factors as the load type, the cause and the length of the outage, the weather, and other pre-fault conditions that makes it a phenomenon difficult to quantify [1]. Over the years, BC Hydro has observed CLPU on multiple distribution feeders across the network. Part of the explanation finds his roots in the massive electrical heating programs driven by the BC government in the sixties through to the early nineties. During winter months heavy load from electrical heating can be a strong source of cold load. The phenomenon can be emphasised for remote communities where outages and restoration times can be longer due to difficulties for field staff to patrol and access the circuit. This section illustrates two cold load pickup examples stations using telemetry data recorded at slow rate and archived in BC Hydro’s Operational Information system. Figure 1 illustrates cold load pickup current as recorded in a 69 kV transmission line that has one rural BC Hydro distribution substation and a small customer owned substation, located in south interior region of the province. In April 2014, after a prolonged line outage of about three hours and 50 minutes, the recorded peak was 2.22 times the preoutage load current. It took approximately 45 minutes for the load to settle close to preoutage level. Figure 2 illustrates the restoration current of a 25 kV distribution feeder in a northern part of the province. The feeder was out of service for about one hour and 40 minutes. The current after the pickup remained above two times the pre-outage level for about eight minutes and finally settling back to the pre-outage level in about 25 minutes.

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Figure 1: Cold Load current profile on restoration of 69kV line along with one distribution substation

Figure 2: Cold load current profile of 25 kV distribution feeder in northern British Columbia

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As illustrated in Figure 1 and 2, the restoration current can be as high as 200% of the normal current and the phenomenon can last for an hour or even longer until settling back to normal conditions. This excessive current can be high enough to overload nonadequately rated high voltage equipment or cause overcurrent protection to operate during unfaulted conditions. BC Hydro’s protection engineers attempt to take CLPU into account in their standard practices while setting their feeder protection, but as presented in this paper there can be issues that require operational solutions to the CLPU phenomenon.

3. BC Hydro Traditional Practices BC Hydro has substations with their distribution buses connected to one or more transformers depending upon their location, reliability requirements, and load demands. However, a single transformer is used for simplicity and illustrative purpose in this section as shown in Figure 3. Since distribution feeders are radial with single and threephase tapped loads, they are protected by inverse-time overcurrent schemes. In the figure, the feeder protection is backed-up by the bus protection which in-turn is backed-up by the transformer high-side protection. The backup for the bus protection can also be on the low-voltage side of the transformer when the station configuration includes more than one transformer. Transformers may have differential protection or an additional overcurrent protection on the high-side for redundancy but are not shown here and discussed.

Figure 3: Simplified one-line of a typical distribution substation

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BC Hydro distribution feeders are standardized for an average load not exceeding 6 MW at 12.5 kV and 12 MW at 25.2 kV. This corresponds to about 300 A, but the feeder’s equipment are rated to carry 400 A continuously. For any planned or unplanned contingencies, the distribution feeders can be loaded up to 400 A. Also, BC Hydro distribution station design limits fault duty to 150 MVA at 12.5 kV and 300 MVA at 25.2 kV2. Further, BC Hydro limits the maximum fuse size to 100T as entrance protection (or equivalent) for three-phase commercial and industrial customers interconnecting at the distribution voltage service level. This design permits the use of standard distribution protection settings at stations equipped with relays and circuit breakers. As previously mentioned, inverse-time feeder protection is coordinated and backed-up by the bus protection in these stations. Based on planned maximum 300 A load current and downstream 100T fuse, the standard pickup for phase inverse-time overcurrent feeder protection relays is 600 A with a 4800 A instantaneous pickup. Since this setting provides a safety factor of two times the planned maximum load, BC Hydro does not regularly experience CLPU issues at stations with standard settings – one exception is reported in Section 4. The standard ground pickup for inverse-time overcurrent feeder protection relays is 240 A with a 4800 A instantaneous pickup, also applied to coordinate with 100T downstream fuse. BC Hydro’s distribution group distributes single phase residential loads to keep unbalance current well below the ground protection to ensure its security. To achieve acceptable protection dependability, BC Hydro practice is to have the phase pickup about 2.5 to 3 times below the minimum fault current, and 3 to 5 times for ground to provide fault resistance coverage. These standard settings have long been applied at urban stations and at other distribution stations with fault levels that meet these criteria. To back up the feeder protection, the phase pickup of the feeder bus protection is 1500 A and is torque controlled to permit the higher loading. Likewise, 400 A is the standard pickup for the ground bus protection relay. Rural or small distribution substations are typically supplied by a single circuit from a remote source and have low fault current levels. Therefore, feeder pickup settings lower than standard are required. Further, these substations are not typically equipped with breakers on the transformer low-voltage sides.

2

In urban area high capacity station distribution buses have very high short levels, BC Hydro connects 400 A and 5% impedance rating series reactor in feeder circuits to limit the fault level.

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Figure 4: Simplified small distribution substations with no low-voltage bus protection (a) station protection with high-voltage fuse (b) station with protection relays and high-voltage circuit switcher

Rural stations built using wood-pole structures without a control building and DC supply are equipped with feeder reclosers backed up by fuses on the high-side of the transformer – see Figure 4 (a). The typical delta-wye configuration used for distribution transformer has winding currents as shown on Figure 5 [2]. Therefore it reduces feeder ground fault current on the low-voltage side to phase current of 58% as seen on the high-side. It is the sensitivity requirements for the ground fault backup protection that often limit the maximum fuse size on the transformer high side.

Figure 5: Current Redistribution from delta-wye transformation [2]

The fuses are designed to withstand 150% overloading beyond which they may start to melt. Hence the cold load inrush currents must not exceed the fuse’s overload rating to avoid any damage. Section 4.2 illustrates how a compromise on fuse size, arising from

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ground protection sensitivity, versus the overload rating can either limit utilization of full station capacity or increase the risk of fuse melting on CLPU. Small distribution substations may have a control building equipped with protective relays, which offers more flexibility than a fuse to manage CLPU concerns. The fuse is replaced by phase overcurrent protection relays installed on the high-side and typically by the neutral relay connected in low-voltage winding of the distribution transformer - see Figure 4 (b). In this configuration, the feeder ground protection is backed up by the neutral relay instead of by the high-side phase protection and thus the ground fault detection sensitivity on high-side is less of a concern. Furthermore, high-side and lowside phase backup protections, and potentially even feeder phase protections, can be torque controlled to enhance security with regards to load. Section 4.3 describes a distribution station where torque control is applied and discusses the limit of this scheme on excessive cold pickups for weak source condition.

4. Cold Load Pickup Case Studies This section describes circumstances that led to outages at three different substations in BC Hydro and lessons learned from these experiences.

4.1. Urban Surrey Substation Figure 6 shows a one-line diagram of Surrey Substation located in one urban Vancouver suburb. Because of location and adequate short circuit levels, standard feeder overcurrent protection settings are in use – except the phase overcurrent pickup is 640 A instead of 600 A due to the CT ratio used and available taps on the electro-mechanical relays still in use at this station. This station is planned to be decommissioned with its distribution feeders transferred to a new substation under construction. The existing station had no history of cold load pickup outages until two occurred recently on 3rd and 4th December 2013 as reported in this section.

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Figure 6: Surrey substation configuration

On November 29th 2013, Surrey feeder 12F53 had an ongoing planned outage and a portion of the load from this feeder was transferred to 12F55. On an unusually cold day on December 3rd 2013 at 8:13 PM, the Surrey substation experienced a power outage on the main feeder bus, 12B1, resulting in all customers supplied from the substation losing power supply. Though the main feeder bus was restored within one hour, the operator was unable to restore 12F55 for an additional seven hours. The inability to restore the feeder led the operator to suspect a fault on 12F55 though no evidence of a fault could be found. The power was fully restored at 4:29 AM the next morning after sectionalizing the feeder and when the feeder load had dropped sufficiently during the early hours of the day. An estimated 19,207 customer-hours of power were lost. In the same morning when station load started picking up, the station experienced another power outage on the main feeder bus at 7:15 AM similar to the previous night. The bus was restored in about 40 minutes. Yet again 12F55 experienced an outage in excess of seven hours. An estimated 16,533 customer-hours of power were lost. An investigation launched after these outages identified the load transfer from 12F53 to 12F55 was the issue since single phase loads were transferred from 12F53 C phase to 12F55 A phase, where generally the load is transferred onto the same phase. The feeder unbalance was therefore higher than usual due to the transferred load and cumulatively caused the bus ground protection to trip as the station load peaked during low ambient temperatures. Subsequent 12F55 trips were due to CLPU currents after the extended bus outage. Originally the operator thought the outage on 12F55 was due to fault on the

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feeder and did not think that it was due to CLPU. They were focusing on isolating sections of the feeder to determine the location of the fault. The lack of SCADA visibility and the absence of remotely controllable devices added to the confusion and delayed the restoration process. Eventually the sectionalized load pickup helped operators energize the feeder even though a CLPU situation existed. Besides the need for a better balanced load transfer, one of the investigation findings stated that operator access to distribution field reclosers would have provided an opportunity to restore 12F55 expeditiously without field crew having to make line cuts. Even though the operator did not recognize CLPU, the problem was resolved because the process for CLPU current management is identical to the process for identifying faulted sections, that is:  

Segment the de-energized feeder into small sections by opening field reclosers Energize the feeder sections in steps starting by closing station breaker (or recloser) followed by closing field reclosers sequentially.

Remote control would have helped the operator to easily identify whether the problem was linked to a faulted circuit or a CLPU situation.

4.2. Rural New Denver Substation New Denver (NDR) is a rural town remotely located in north central British Columbia. The town is supplied by a small distribution substation, which is located at end of a radial 69 kV line, namely 60L210. Figure 7 illustrates the simplified one-line diagram of the station with two transformers and two feeder reclosers – one feeder on each transformer. The station has both summer and winter peaks. It is a typical small station within BC Hydro built using wood-pole structures and without a control building, battery systems, or relays. Transformers are protected by their own fuses, which also backup the feeder reclosers. The station is not designed for parallel transformer operation.

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Figure 7 New Denver substation one-line diagram

4.2.1. Station Fuse Size and Recloser Pickup Since the fuse is providing backup to the feeder recloser, it is sized to melt for the minimum fault current on the transformer low-voltage side. Table 1 summarizes fault currents at NDR for weak source conditions as seen by the feeder and transformer fuse. Due to the fault current redistribution through the delta-wye transformer, the line to ground fault is the constraint on fuse sizing since the fuse sees only 58% of the per unit low-voltage fault current. Fault Type

LV Fault HV Fault Current (A) Current (A) Single line to ground 1287 142 Line to line 869 192 Line to line to ground 1293 192 Three phase 1003 192 Table 1: Short circuits level at New Denver under weak source conditions

The following two criteria are applied in selecting transformer fuse size:  

Pickup Margin factor: A pickup margin of 2.5 to 3 is applied between the minimum fault current seen by the fuse and minimum melting current Minimum melting current factor: Power fuses are typically designed to melt at current levels over 200% of the rating. Therefore to determine the fuse rating a 200% factor must be taken into account regarding the desired pickup value.

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Use the minimum ground fault current from Table 1 to apply the above criteria: 

Pickup Margin factor:



Minimum Melting :

Therefore a 30E fuse was selected and first installed at NDR to provide reliable fault detection. When selecting the station recloser setting pickup coordination margin was applied, and a pickup of 200 A was selected. Though the recloser pickup restricted loading, it provided good coordination with the upstream fuse.

4.2.2. Cold Load Pickup Issue As rule of thumb, fuses can typically be loaded up to 150% of their “E” rating but loading beyond this point can cause unnecessary fuse operation [3]. At NDR, the selected 30E fuse can be overload up to about 45 A or 4.18 MVA whereas the recloser with a 200 A pickup limits the station load capacity to about 4 MVA per feeder. Thus, the 200 A pickup is more restrictive than the fuse and risks recloser misoperation for 2 MVA or higher loads during re-energization assuming 200% cold pick-up inrush. The fuse size and recloser settings discussed above worked well until 2010 when the station load grew steadily and exceeded 2 MVA per feeder. Cold load pickup peaks of 200% were observed leading to rather long outages. In 2010, NDR experienced multiple extended outages due to unsuccessful feeder restoration consecutive to an outage of the 69 kV line feeding the substation. Figure 8 shows multiple unsuccessful attempts of load restoration at NDR after a feeder outage. Since there was no SCADA installed at this location, telemetry from 60L210 at the source station was used. NDR 12F52 recloser was found faulted and the load was transferred to 12F51. Following multiple unsuccessful attempts to restore 12F51 after the load transfer, the field personnel realized the problem was related to CLPU and decided to sectionalize the feeder in order to restore the load. The total restoration time was about five hours mainly slowed down by the travel time of the staff to these remote locations and the time for field personnel to identify the cause of the problem.

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Figure 8: Unsuccessful load restoration at NDR (January 1st, 2010)

To avoid having the recloser trip under cold load pickup conditions, the recloser phase pickup was then increased to 400 A from a previous pickup of 200 A while the fuse size was increased to a 40E fuse. As calculated previously, this fuse size was not providing enough fault sensitivity under one level of contingency but was accepted as a flouting of standard practices in order to accommodate the growing load. At that time, it was not recognized that the reclosers’ increased settings did not coordinate with 40E fuse near pickup or low fault current. Unfortunately, the station experienced other extended outages after this change. The NDR T1 fuse blew on 7th June 2011 and 8th January 2013 for feeder faults. There were also three occasions where the transformer fuse blew on restoration of the 69 kV line after a planned outage. During one of those outages, it took up to 17 hours to restore the power during a storm because no qualified staff could be found to operate the station equipment; eventually when resources were allocated, access to the station was found to be difficult. The reason the fuse was blowing before the recloser could trip was due to the miscoordination between the fuse and the recloser at low fault levels. Figure 9 illustrates the miscoordination following the revised recloser settings, which led to fuse operation. A final request was initiated to increase the fuse size again but this was rejected by protection engineers since the existing fuse was already oversized from a protection point of view. Then to avoid miscoordination with fuse, the feeder recloser pickup was reduced to 300 A from 400 A.

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At low fault levels there is miscoordination. The recloser does not pick up the fault whereas the fuse does and could blow for the feeder fault.

Figure 9: Coordination between 40E fuse and the feeder recloser with a 400A phase pickup setting for a Line to Line fault. Miscoordination can be observed at low fault levels.

4.2.3. Mitigation After these events, it was recognized that the protection scheme of NDR reached its limits as the fuse and protection settings were limiting the load capacity of the station but could not be increased anymore without unacceptable loss of sensitivity. Different options were investigated to solve NDR’s problem. The decision was made to install new digital protection relays with a high-side breaker to replace the fuse. Protection relays would offer more flexibility to provide adequate coordination and increased sensitivity

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and load capacity. This was recognized as the best technical solution to accommodate New Denver’s load with acceptable protection settings but it raised two concerns: 1. New circuit breakers and protection relays require new station facilities including a control building, AC-DC services, battery, etc. The total estimated cost was about $10M, which seemed unjustifiable for such a small station having minimal load growth. 2. Major infrastructure projects have considerable lead-time. By the time the project would be completed, NDR would face at least two winters with more CLPU situations. Committed to find a mitigation solution before the winter, BC Hydro engineers took another look at the New Denver problem to understand thoroughly the situation and pinpoint the actual issue. It appeared that the continuous station load was still within the station equipment rating and compatible with the protection settings and fuse rating. Only the marginal load increase over the last years had unveiled an existing CLPU situation when restoring NDR. In the past, the CLPU phenomenon was handled by the margin in the station equipment rating and protection settings but it turned out that the load increases had consumed the entire available margin. The operational solution to restore the load was known for a long time and consisted of sectionalizing the feeder. It has been done in the past but led to unacceptable restoration durations determined by both the travel time to site and staff availability. If sectionalizing used to be considered as a non-viable solution for the reasons aforementioned, recent grid modernization initiatives have considerably changed the context. Indeed as part of the BC Hydro’s distribution automation strategy, equipment installed on the distribution feeders, like reclosers and circuit switches, are being replaced and provided with remote control from the control center. Field equipment operations like feeder sectionalizing can therefore be done remotely avoiding manual switching and providing reduced restoration time. Feeder sectionalizing has become a much faster solution for feeder restoration. A decision was made to provide remote control of the station and field reclosers at NDR and delay any major investment. Besides delaying any major investment, the main benefit of this solution is that the feeder recloser protection settings can now be set with reduced cold load pickup constraints. Furthermore, the telemetry data from the SCADA reclosers allowed planners to more effectively determine the feeder characteristics and provide more accurate protection settings regarding existing load at the station. It also allowed planners and operators to detect and address unexpected feeder load unbalance that was actually increasing the effect of CLPU when trying to restore the load.

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4.3. Small Long Beach Substation Long Beach Substation (LBH) is another remote, small distribution substation. The station is located on Vancouver Island at the end of an 84 km radial 69 kV line, namely 60L129 (see Figure 10). The line has several tapped generators as shown on Figure 11. These generators are disconnected by direct transfer trips when 69 kV line trips and thus their fault current contributions are not available during line pickups. LBH has two delta-wye transformers (T1 and T2) with each transformer feeding two separate feeder sections i.e. the station is not designed for paralleling of the transformers. Low fault currents due to the changing system configuration have historically made feeder protection coordination challenging.

Figure 10: Long Beach station location

Figure 11: LBH Area simplified one-line diagram

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LBH is equipped with relays, which offer more flexibility than the fuse to the station and feeder protection. An overcurrent protection on the transformer high-side is a backup to the feeder phase faults. Additionally, an overcurrent element in transformer low-voltage neutral provides backup to the feeder ground protection – see Figure 4 (b). Taking into account credible system contingencies, the lowest fault current seen LBH high-side backup protection is expected for a phase to phase fault on the 25 kV distribution feeder. In this case, the fault current at 25 kV could be as low as 839 A. In order to follow BC Hydro standard practices described earlier in this paper for fault sensitivity, the feeder pickup should be set with a 2.5 times margin over the minimum fault current: 

Pickup Margin factor:

LBH feeders have winter peaks strongly reinforced by the electrical heating present in the area. The load in the area can be as high as the transformer rating (12.5 MVA) under normal conditions. Thus, the security margin on the pickup setting determined above: 

Load security margin:

In other terms, the settings offering the minimum fault sensitivity would only cover a 116% temporary load increase whereas CLPU can be as high as 150% or 200% of the normal load. Since this is below 150% of the load, under voltage torque control has been implemented on LBH feeders. Under fault conditions, the feeder is expected to see a drop in voltage in which case the relay will be allowed to operate when the voltage drops below a predetermined pickup value. However under normal load condition, the voltage is expected to stay healthy and the torque control should prevent the protection to operate. A value of 0.9 pu was used when the torque control scheme was first installed and allowed the overcurrent pickup to be reduced to 180 A. On December 7th, 2000, the feeder protection misoperated during a restoration under heavy load conditions. The current drawn by the feeder was high enough to reduce the voltage under the 0.9 pu value. The total restoration time was about eight hours and was found unacceptable. A request was initiated to use lower voltage torque control settings in order to accommodate more load. A 0.82 pu pickup setting for voltage torque control was then proposed and implemented. Because each extra load carrying capacity is provided at the expense of reduced fault sensitivity, the pickup settings could not be lowered further without the risk of not operating for a fault condition and creating damage to the system. The 0.82 pu setting was described as the ultimate comprise acceptable by protection engineers. Operators were told to sectionalize the feeder if further load capacity was required. During 2007 winter, a similar situation occurred and took about four hours for the field staff to sectionalize and restore the entire feeder. On February 16th, 2014, a fault was detected on 60L219 and the protection system correctly tripped the line but auto-reclose failed. Per BC Hydro Operation Standards, one manual reclose was attempted, which also failed. The line was then patrolled to look for a

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permanent fault. The patrolling took approximately five hours to be completed. Once completed without major findings, another manual reclose was attempted and was successful. However during the line restoration, LBH 25F52 tripped.

Figure 12: Long Beach 25F52: unsuccessful feeder restoration

Records from the protection relay (see Figure 12) show that the current reached 345 A and the voltage dropped to 20.3 kV. Since the feeder protection pickup value was set at 180 A and the torque control was set at 20.6 kV (~82%), the protection operated. The extended outage had created a CLPU situation and the feeder current on restoration was above the protection setting and high enough to reduce the voltage below the torque control setting. Generators on the transmission line were previously tripped out during the line outage to prevent islanded operation and therefore could not help to strengthen the system and avoid voltage drop, which in-turn led the protection to operate. In order to deal with the extra amount of load, the decision was made to pick up the feeder in sections as decided after event from 2007. Since 2007 the sectionalizing devices (field reclosers) on the LBH feeders had been equipped with remote control, which sped up the restoration process considerably. Figure 13 shows the feeder current recorded from telemetry and illustrates the staged load restoration.

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Figure 13: Staged load restoration at Long Beach

The feeder restoration sequence happened as follows: [a]. 11:23 PM: Line is restored but restoration load is too high due to CLPU situation and feeder trips. Total current is about 345 A. This represents about 205% of the expected load (168 A). 11:23 PM – 11:28 PM Operators identify this is as a CLPU situation and decision is made to pickup the line in sections. 11:28 PM – Control center open four reclosers located on the line. [b]. 11:29 PM – First section of the feeder is picked-up. Total current: 107 A [c]. 11:40 PM – Second section is picked-up: total current 117 A [d]. 11:47 PM – Current has settled down to 98 A and section 3 is picked up. Total current is 272 A. [e]. 00:03 AM – Current has settled down to 220 A and section 4 is picked up. Total current is 308 A. [f]. 00:21 AM – Current has settled down to 260 A and section 5 is picked up. Total current is 281 A. [g]. 02:30 AM – Current has settled down to normal condition value. During the restoration process, the current rose above the overcurrent pick-up threshold (steps [d] to [g]) but the stepped load pick-up prevented voltage collapse and protection operation. The total feeder restoration time was 58 minutes. Compared to the similar events on the same feeder in 2006 and 2007, this event represented a considerable improvement for distribution customer reliability. Protection settings had not changed and the sequence of events was similar to what it was 10 years ago but field equipment was since equipped with remote control for the operators. The CLPU situation was

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considered resolved because the restoration time had become more acceptable; the pressure to desensitize protection relay settings could be released.

5. Remote Control Design A key element in the mitigation of problems described above is the ability for the operator to remotely control station and field equipment. As BC Hydro customers are widespread across the province, distribution equipment may be located in remote areas. Historically, SCADA was not provided to small distribution station and field equipment. The installation of telecommunication links to these remote locations required considerable investment to provide available telecommunications technologies like a leased line or microwave link. The traditional substation SCADA interface traditionally also required the installation of Remote Terminal Unit (RTU) and telecommunication equipment in a control building. These costs were not justifiable for small equipment therefore the control center was operating without visibility of these assets; relying on customers’ calls to an outage management system to identify power outages and local field staff to remediate. Wireless telecommunications technologies offer a wider range of options for control planners. Recently BC Hydro has put strong emphasis on using this technology in order to improve operator and field worker efficiency by reducing the number of site visits. The goal was to provide the control center with remote control of frequently operated equipment. To achieve this goal, BC Hydro’s distribution and SCADA design groups initiated an ambitious Distribution Automation (DA) project. The remote control solution has been developed over the past decade and is now a mature implementation. DA includes reclosers and automated switchgear primarily but also includes voltage regulators, shunt capacitors, and other devices. Figure 14 shows locations of BC Hydro field reclosers in 2014 and highlights that about 55% percent of them are provided with SCADA.

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Figure 14: Recloser and SCADA visibility within BC Hydro (2014)

DA traditionally uses IP based cellular communications for connecting devices to provide SCADA. BC Hydro has leased a private, dedicated network through a cellular service provider, who provides this service via the public cellular system. This system is accessed via a firewalled Ethernet connection to the service provider’s data center. While the cellular network is most commonly used, recently BC Hydro has been deploying our own private WiMAX network in key areas and satellite communications as backup for remote areas. The network preference for DA devices is WiMAX where available, cellular, then satellite. Figure 15 shows the high level architecture used for DA including SCADA data path.

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Figure 15: BC Hydro Distribution Automation (DA) architecture

A gateway device is used as DNP master for remote data concentration of reclosers. The reclosers are configured to provide unsolicited report by exception, but the gateway will also perform integrity polls on a regular basis to ensure all data is collected. The gateway is preconfigured for up to 100 reclosers since the DA device DNP maps are standardized in all devices of the same type. The gateway device itself reports to the Energy Management System (EMS) at real-time polling intervals like typical substation SCADA RTUs. The gateway acts as a filter to any communication issues that occur on the wide area networks since the EMS cannot handle the intermittent failures that may occur. When operators at the control centre issue SCADA commands, they are first issued to the gateway, which then issues the command to the desired device. Latency issues are a concern in this architecture as field devices can take a few minutes to return an acknowledgement of the selected operation (depending on the network used); however this is a known issue to operators and is accepted since the alternative requires sending a field worker to the remote location. Operators are also able to open the reclosers remotely when the equipment is de-energized due to the built-in recloser battery system, which gives them control for up to 24 hours after AC supply is lost. The same Ethernet communication link can also be used through a firewall in order to access the controllers for engineering tasks. This allows our engineering staff to retrieve live feeder information, fault event records, or proceed with firmware upgrades.

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Until recently there were approximately 30 stations with no SCADA connectivity, such as NDR. Most of these stations do not have a control building. A project was initiated to add SCADA to these stations. Considering the amount of field devices requiring an upgrade, the project needed to navigate between two major constraints: installation cost and deployment time per site. With the DA SCADA architecture now considered mature, BC Hydro has begun to connect station reclosers to SCADA using this approach. The design satisfies both constraints:  Communication equipment (antenna and Ethernet modem) can be installed within the device’s control enclosure sharing the same auxiliary power supply. This avoids the need for control building or station services and helps to reduce costs.  EMS servers and the gateways are pre-configured and require minimum amount of time to be updated and tested, reducing both cost and time.  The design is standardised for all field devices and reduce site specific engineering to his very minimum. Installation time is minimized by swapping existing controls with pre-commissioned replacements on site. NDR was one of the first locations where both station and field reclosers were connected to SCADA using the DA architecture, specifically to alleviate the CLPU concern. The operators are taking advantage of the ability to remotely control and monitor equipment using the DA system to mitigate CLPU by sectionalizing feeders remotely.

6. Conclusions Utilities are under increasing pressure to reduce cost of service and improve reliability. They must demonstrate acceptable reliability performance in order to convince regulators to approve their revenue requirements. CLPU situations, discussed in the paper, led to outages as long as 17 hours. The problem is exacerbated in rural locations experiencing rugged winter where access to the equipment can be slowed down and qualified staff might not be available. Status quo involving these long outages is not an acceptable option to BC Hydro. To avoid this situation, pressure is frequently transferred to the protection engineers to desensitize the protection and accommodate higher peak load. About two years ago, BC Hydro embarked on a program to install SCADA on distribution substations, particularly at remotely located rural distribution substations and field reclosers. Impetus of this initiative is to improve reliability of distribution supply. SCADA telemetry helps operators in making informed decisions related to outages like identifying CLPU versus faulted circuit situations. During the restoration process, the ability to remotely switch reclosers brings efficiency by reducing or even eliminating field crew travel time, which in turn reduces outage duration. At NDR, a major upgrade of the station to improve reliability and accommodate CLPU situations was approved and estimated to be $10M. However, as an alternative, BC Hydro instead implemented a cost effective Distribution Automation design to mitigate CLPU outages. Remote control of field equipment is an effective tool to manage CLPU without a significant cost. Although it was well known that cold load pickup can be managed by restoring load in sections, it was not practical without remote control.

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In one of the examples presented in the paper, the restoration time dropped to less than one hour after remote control became available from about 4 to 10 hours beforehand. Examples presented in the paper showed that BC Hydro had experienced CLPU of up to about 2.5 times the peak load in parts of province. By using remote controlled reclosers, they can be reduced to lower levels depending on number and location of reclosers and time to reclose. The pressure to reduce fault sensitivity can thereby be released. It is absolutely critical in vertically integrated utilities for operation, field and planning staff to work together and look for innovative solutions such as described in this paper to reduce cost and deliver reliable power to meet or exceed customers and regulators expectations.

7. References 1. Cold Load Pickup Issues. Power System Relay Committee. (2013). IEEE Power Engineering Society. 2. Selection Guide for Transformer – Primary Fuses in Medium and High-Voltage Utility and Industrial Substations”. (October 10, 2005). S&C Electric Company. 3. S&C Power Fuses Types SMD-1A, SMD-2B, SMD-2C, SMD-3, and SMD-50 – Continuous, Daily, and Emergency Peak-Load Capability. (August 6, 1984). S&C Electric Company.

8. Acknowledgments Authors wish to thankfully acknowledge their colleague Ms. Jennifer Coote who contributed to the discussions on transformer fuse applications and the review of the document.

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