Load Term 2

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  1. Define feeder cable.
    Feeder cable is the underground portion of a feeder that delivers power from the substation to the first switchable device in the field.
  2. Where is the isolation of a feeder cable typically mimicked?
    The isolation of a feeder cable is typically mimicked in both AREVA and POCC.
  3. How do cablemen request for station risers to be removed in advance of planned feeder cable work?
    When submitting there Outage Request Form through CROW, the cablemen will request the risers be removed under the “Notifications” section in the “Comments” box addressed to the station electrician.
  4. How is the removal of station risers mimicked?
    The station pothead symbol is a selectable point in AREVA and can be toggled to mimic the state of the risers.
  5. What is ferroresonance?
    Ferroresonance exists when switching feeder cables and voltage regulators in series with single-phase pothead disconnects or sleeves. With one or two phases open during switching, the de-energized cable provides capacitive reactance while the regulator on an energized phase provides the inductive reactance. As the applied voltage changes through the 60 cycles/second, so will the value of inductive reactance. This allows the possibility for capacitive and inductive reactance to become equal at points in time, cancelling each other out and leaving on resistance to restrict the flow of current. This can cause the circuit to resonate for at least part of the cycle, creating the possibility for excessive voltage to appear across the open phase(s).
  6. Where is the feeder cable switching procedure to be followed by Load Operators found?
    A section of 2T-27 is dedicated to “Feeder Cable Switching”.
  7. What must be done prior to opening pothead sleeves on a feeder cable and why?
    Confirm current to be less than 2 amps to insure load will not be dropped or a parallel will not be broken on the sleeve.
  8. What is a standby circuit?
    A standby circuit is a circuit capable of carrying either all or part of the load of the feeders to which it provides standby service depending on whether it is a dedicated or partial standby circuit.
  9. How can a standby and partial standby circuits be identified on AREVA and POCC?
    Dedicated standby = Solid red box around feeder text

    Partial standby = Dotted red box around feeder text
  10. How can maximum demand readings be used to help make operational decisions?
    Max demand readings tell us what amount of current is flowing through each phase of a feeder during it’s peak load in a given period of time. When transferring part or all of a feeder to another, operators not only need to be concerned with the real-time readings for the actual switching, but also need to know whether or not the feeder that ends up carrying the load will have the appropriate ratings to support the load at its peak. This will influence an operator’s decision on which circuit(s) can carry the full or partial load of a feeder that is going out of service.
  11. How can a feeder’s kVA report be used to help make operational decisions?
    A kVA report tells an operator what percentage of a feeder’s load is allocated past a given switch or device. This can help a load operator decide what parts of a feeder can be off-loaded onto other circuits during a planned or forced outage while not exceeding any ratings.
  12. What operating prints are currently used in the Control Centre to operate and mimic the URD system?
    • Underground Distribution Diagrams
    • Underground Distribution Schematics
    • Distribution Operating Diagrams
  13. Describe a URD loop system?
    When an Underground Residential Distribution System includes multiple feeds it is referred to as “Loop-Fed”. Normally-open points are placed throughout the loop system to make sure transformers and switching units are fed from only one source at any given time. These alternate feeds and normally-open points are designed to limit outages to customers when isolation to URD equipment is required and to provide the ability to manage system load.
  14. What is the normal procedure for switching on a URD loop system?
    The normal procedure is “break” before “make” when switching unless proper testing has been performed to ensure correct phasing.
  15. What factors must be considered when closing a loop on the URD system and why?
    Considerations must be made to limit the duration of any customer outage and to limit the number of customers affected. Another thing to consider is the magnitude of the loop current that could flow. When paralleling circuits through the URD, loop currents could be large enough in magnitude to blow fuses or even overload URD equipment.
  16. Where is the Communication Protocol to be followed by the PIC and field worker found?
    Safety Practice Regulations & S.O.O. 1T-13.
  17. What category of PSSP must a worker be authorized to in order to receive an SPG?
    At least Category 5.
  18. What is a Designated Isolation Point? Where would a DIP be recorded?
    A DIP is used where equipotential grounding is not practicable at the worksite. This DIP will be under worker control by placing a Grounding/Blocking Tag immediately upon receiving a SPG. It must be recorded on both the BC Hydro Control Centre’s and the field worker’s SPG forms.
  19. What fundamental questions must be answered by the field worker when returning an SPG to the PIC?
    • Has Worker Protection grounding/bonding been removed?
    • Are risers removed?
    • Is phasing required?
    • Is the equipment ready for service?
  20. What System Operating Order defines the life cycle of an SPG card?
    S.O.O. 1T-07H
  21. What are the PIC’s responsibilities following the return of an SPG declared “Not Ready for Service”?
    • Check “Not Ready for Service” box and indicate the reason for the condition.
    • File SPG card with “Returned” SPG cards.
    • When issuing new SPG to make equipment ready for service, inform SPG receiver of “Not Ready for Service” status on previous SPG card.
    • Remove old SPG card from “Returned” SPGs, strike with a single line, and file with “Completed” SPGs.
  22. What are the PIC’s responsibilities following the return of an SPG with “Worker Protection Grounds Applied”?
    • Check associated box on SPG card
    • On electronic mimic display:
    • i. Place removable Field Ground device symbol within isolated zone and tag it with a GROUNDED tag, or
    • ii. Place a GROUNDED tag on at least one of the devices associated with the isolated zone, referencing the returned SPG number.

    • Not on electronic mimic:
    • i. Place equivalent GROUNDED tag on paper mimic with reference to returned SPG number.

    • File SPG card with “Returned” SPG cards.
    • When issuing new SPG for same equipment, inform SPG receiver that Worker Protection Grounding/Blocking remained on from previous SPG.
    • Remove GROUNDED tag upon issuing new SPG and move old SPG card to “Completed” file after striking with single line.
  23. What are the PIC’s responsibilities following the return of an SPG with phasing requirements?
    • Check “Phasing Required” and “Ready for Service” boxes on SPG card.
    • Place “Not Available” tag on electronic mimic display describing the phasing requirement.
    • File SPG card in “Returned” SPG file.
    • Once phasing is completed successfully, remove N/A tag, strike old SPG card with single line and move to “Completed” SPG file.
  24. What is a Guarantee of Isolation and how is a GOI recorded?
    A GOI is a means of guaranteeing that an area will remain isolated between different Operating Authorities. A GOI is recorded with a SPG card.
  25. What is a Transfer of Operating Authority and how would a TOA be recorded between a Load Desk and adjacent Grid Desk at FVO?
    A TOA allows adjacent PICs to move an operating boundary such that the required lines or electrical and mechanical equipment are all within one area of control. The PIC who has transferred Operating Authority and the PIC who has received the Operating Authority will record the transfer in the official desk logs. The PIC who receives the transferred Operating Authority will tag the boundary devices with TOA tags.
  26. What category of PSSP must a worker be authorized to in order to receive a Live Line Permit?
    Category 5
  27. What category of PSSP must a worker be authorized to in order to receive an Assurance of No Reclose Permit?
    Category 4
  28. What is a Guarantee of No Reclose?
    A stated and duly logged guarantee between the PICs of different Operating Authorities that a specified conductor or equipment shall not be reclosed manually or automatically until the PIC who has received the guarantee authorizes reclosing.
  29. What tool is used by the Load Operator to log the issuing and returning of Live Line Permits, Assurance of No Reclose Permits, and Guarantee of No Recloses?
    CROW P3
  30. What is the purpose of a CNE?
    A CNE allows an Operating Authority to test energize plant additions, modifications, and replacements. When the CNE is complete and signed off, the equipment or circuit becomes part of the Power System.
  31. What part of the power system requires a CNE for the commissioning of equipment?
    • All Station and Transmission projects for which T&D has asset responsibility and which impact operating one-line diagrams.
    • WPP equipment in BC Hydro Generating Plants.
  32. Following the completion of a CNE, what must be done if an updated EMS one-line display is not ready for upload to reflect the changes to the system?
    • · On electronic mimic display select “PSSP Mimic Display” to display drop down menu and select “Check Paper One-Line” red button. This will enable “CHECK ONE-LINE” yellow flashing text on the electronic display.
    • · Log in CROW as EMS/SCADA condition for station with “XXX Check One-Line” as a description where “XXX” is the station abbreviation. In comments explain discrepancy between electronic mimic and paper one-line.
  33. What is a Plant Alteration?
    A Plant Alteration (PA) is the addition or removal of high-voltage (less than 60 kV) plant equipment on the distribution system.
  34. What part of the power system requires a PA for the addition and removal of plant?
    All changes to the distribution system which impact the operating records require a PA.
  35. What is the purpose of the PA process and what operating order is the process defined in?
    The Plant Alteration (PA) process is in place to ensure that the parties responsible for the operation of the electrical system maintain accurate and up-to-date operating drawings and mimics. The PA process essentially begins where the CNE process ends. In other words, it covers the distribution primary from the feeder-cable terminations and overhead-feeder connections in the substation outward.
  36. What is PAT?
    PAT is a computer program used to track a PA’s progress from its time of issue to its completion. It will keep track of a PA’s new drawings as they are updated, approved, and issued.
  37. What is the role of the PA Coordinator?
    • · When a new PA is issued through PAT, the PA Coordinator will print a hard copy of the PDF and attach a PA cover sheet to it. This will form the PA package and will be filed in the PA filing cabinets in the control room.
    • · Once the PA cover sheet has been marked as “PA Completed”, the PA is then handed off to the PA Coordinator. The PA Coordinator will mark the PA as complete in the PAT system and will note the drawings requiring mark up by drafting. The PA Coordinator will also request new drawings to be sent to FVO through PAT if required.
  38. When working on a PA to install a new underground loop connection, at what point is a Safety Protection Guarantee required?
    An SPG is required once the installation of a cable will result in the possible creation of a loop. Before terminating the last cable at either end, worker must request SPG from the PIC with isolation devices from both ends of the cable. No SPG is required to pull the cable in an empty duct. Cable is installed without any SPG.
  39. What are the Load Operator’s responsibilities following the completion of a PA?
    It is the Load Operator’s responsibility to asses the PA and to determine what operating drawings and operating tools have been impacted as the PAs are completed. The Load Operator must ensure all operating drawings and the POCC mimic are updated in real time to reflect the system accurately. Any changes to paper drawings will be initialled and dated by the operator.

    Upon completion of the PA, the operator will sign off, date, and note the name of the electrical worker completing the PA on the PA sheets. If new drawings are required, requests are made on the PA cover sheet. The PA cover sheet will then be marked as “PA Completed” and sent to the PA Coordinator.
  40. What is a PACTOR?
    A PACTOR is the commissioning process to be adhered to for all Protection, Control and Telecommunications equipment for which BCH has asset management responsibility and operating responsibility.
  41. When commissioning protection, control, and telecommunications equipment; when is a PACTOR not required?
    When commissioning protection, control, and telecommunications equipment in addition to power system equipment which requires a CNE, the CNE is sufficient for both without the addition of a PACTOR.
  42. Briefly describe the process for commissioning a brand new field recloser with supervisory control.
    After installation and testing of the supervisory device(s), the Field Coordinator shall prepare a PACTOR listing all equipment or items including any outstanding deficiencies and operating limitations. A copy, e-mail or facsimile of the completed PACTOR (uniquely numbered) including any outstanding deficiencies, will be provided to the BC Hydro Control Centre.

    After receiving PACTOR, BC Hydro Control Centre will authorize to place the supervisory devices in service.
  43. What is a Declaration of Compatibility?
    A Declaration of Compatibility consists of forms that are provided to the Control Centre signed by the Customer and the assigned Project Manager or Field Coordinator. They let the Control Centre know that the several stages of energization have been successfully completed by the IPP.
  44. What is differential protection?
    Differential protection compares the current going into the transformer with the current coming out of the transformer using CTs with different ratios and a differential relay. When the difference between these two currents has exceeded a pre-determined value, the differential protection will operate.
  45. What is the advantage of using differential protection over simple over-current protection to protect transformers?
    Differential protection is able to differentiate between an internal fault and an external fault. During an internal fault, the difference in current flow through each CT secondary on either side of the transformer will exceed the predetermined value, causing the protection to operate. However, during an external fault the current flow through either CT secondary should be equal, not exceeding our predetermined value. During an external fault this allows the appropriate external protection to operate instead of the transformer’s protection.
  46. What is the limitation of using over-current relays to employ differential protection?
    Because not all CTs perform exactly alike and ratios don’t always match, differential error current can flow during an external fault. For this reason, a buffer is required and the over-current relay must be set with a higher differential to allow for this error. This in turn will reduce the sensitivity of the protection.
  47. How do percentage differential relays increase the sensitivity of differential protection?
    For the relay to operate protection, the differential current must be greater than a set percentage of the CT secondary currents. This means the higher the current on a through fault, the higher the required differential current for the protection to operate. This eliminates the concern for differential error currents during external faults, and thus increases the sensitivity of the protection.
  48. How can magnetizing inrush current pose a problem to differential protection?
    Magnetizing inrush currents can be seen as an internal transformer fault to a differential relay because it is establishing the magnetic field and therefore does not flow out the other side of the transformer. Magnetizing inrush current has a high harmonic content and is especially rich in second harmonic.
  49. How are a gas relay’s alarm and trip outputs triggered?
    Gas relay alarms are triggered when a small fault causes a gradual accumulation of gas. This gas will move the oil in the relay chamber and the associated float as well. Once the float passes a predetermined point, it will operate a micro-chip which then initiates an alarm.

    A trip, on the other hand, is triggered when a large internal fault occurs. A rapid build-up of gas pressure occurs as the arcing vaporizes the oil. This pressure moves a bellows in the gas relay chamber which causes a micro-chip to initiate a trip.
  50. What two conditions in combination will trigger “bullet-hole” protection?
    A low oil alarm and a gas accumulation alarm together will trigger a bullet-hole protection operation.
  51. How does a winding temperature device measure temperature? What is it used for?
    A winding temperature device has a heater which is fed from a CT in the transformer winding. Temperature measured by the thermometer depends on the top oil temperature and the current in the transformer winding.

    It initiates alarms, cooling, and tripping as required.
  52. How are faults cleared on substation transformers without high-side circuit breakers?
    If a transformer has no highside breaker, then either a transfer trip is sent to the remote line terminal or a SOG is applied to force operation of the remote line terminal protection.
  53. What is transformer auto isolation?
    After a CB has tripped to clear a transformer fault, some transformers have an auto function that will open the transformer disconnects to isolate the transformer. This is known as transformer auto isolation and it allows the blocked closed condition to be removed in order to restore other equipment to service.
  54. What type of relay is generally used in bus protection?
    Over-current relays are generally used in bus protection.
  55. How must the phase and neutral relays of bus protection be set in terms of coordination?
    When a fault occurs, the relays furthest from the source must respond the fastest.

    The phase relays must coordinate with feeder phase over-current relays and the neutral relay must coordinate with feeder neutral relays.
  56. What is the purpose of torque control and how does it function?
    Torque control is used to ensure that bus protection does not operate on load current. Under-voltage or distance elements are added to control the operation of feeder bus over-current relays. These elements operate during faults (on bus and relatively close-in sections of the feeders), but not for heavy loads.

    During heavy load periods, bus voltage remains near normal. During a bus fault, the voltage will drop drastically. For this reason an under-voltage relay can be used for torque control.
  57. What is the risk in using the under-voltage method of torque control?
    Loss of voltage to the under-voltage relay may cause bus protection misoperation.
  58. Why would a distance relay be used to provide torque control?
    If the source impedance is low compared to the series reactor impedance then most of the voltage drop would be across the reactor when a fault occurs beyond the reactor. This may leave insufficient voltage beyond the reactor to operate an under-voltage relay. For this reason a distance relay would be used to provide torque control.
  59. What is the risk in using the distance method of torque control?
    Loss of voltage to the distance relay will prevent bus protection operation for a bus phase fault.
  60. Describe typical substation feeder relaying.
    Feeder relay protections usually consist of four over-current relays - one for each phase and one for neutral. Each relay usually contains an inverse time over-current element and an instantaneous over-current element. The three phase relays would have the same settings, but the neutral relay would be set more sensitively because it does not see normal load current. It must be set higher than any load imbalance that may occur.
  61. How is a feeder fault cleared if the feeder circuit breaker fails to operate?
    If the feeder CB fails to operate when a feeder fault is present the next upstream protection should operate if coordination functions properly. In this situation the next protection in line should be the associated bus protection.
  62. How does a fused cutout function?
    Fused cutouts are used to protect and isolate distribution transformers, electrical apparatus, and primary distribution lines. The hinged portion of the fused cutout is held closed by a replaceable fuse link when no fault is present. When a fault does occur on the transformer or primary, the fuse link melts, allowing the hinged portion to drop open. This isolates and restricts the outage to a small area with visual separation, allowing the open cutout to be easily located.
  63. What is an expulsion fuse?
    An expulsion type fuse is one where the heat generated by the melting during a fault creates gases that expel the arc products from the fuse tube.
  64. How does the fault protection provided by vista switchgear differ from that of a switching kiosk?
    A switching kiosk uses fuses for fault protection while vista switchgear will used a vacuum fault interrupter in series with its load-interrupter switch.
  65. How are the majority of dead-front transformers protected?
    The majority of dead-front transformers are protected by a series combination of a replaceable expulsion fuse and a back-up current limiting fuse. The expulsion fuse is designed to protect against overloads and faults on the secondary side. The current limiting fuse protects against short circuits on the primary winding and limits the energy that is dissipated in the transformer tank. The current limiting fuse is mounted inside the transformer tank and is not replaceable in the field.
  66. Can a bay-o-net fuse be used to break load in an LPT?
    Although the manufacturer says Bay-O-Net Fuses can break load, it is not BC Hydro's practice to break load with any pad-mounted transformer fuses.
  67. How are shunt capacitor banks primarily protected? What benefits does this provide?
    Shunt capacitor banks are primarily protected by individual capacitor fuses, which are supplied as part of the capacitor bank. These fuses protect the individual units.

    Some of the benefits this provides include:

    • Maintain service continuity, removing only a failed can
    • Prevent damage to adjacent capacitors and equipment, or injury to personnel
    • Provide visual indication of a failed unit
  68. What means of protection can be provided to isolate a shunt capacitor bank from the system in the event of a major fault?
    Phase fuses or phase and ground over-current relays may be used between the system and the capacitor bank for major bank faults. Additionally, over-voltage relays are set to respond at a pre-determined value to the shift in neutral potential caused by failed cans.
  69. Why is neutral-shift over-voltage protection applied to shunt capacitor banks?
    • A failed unit on a capacitor bank causes a change in impedance on the leg having the failure. This change of impedance causes a proportional shift in the neutral potential.
    • When the shift exceeds a pre-established threshold level, breaker tripping is initiated by appropriate relay operations.
  70. What type of feeder outage will a Load Operator be most concerned with?
    Load Operators are most concerned with sustained outages on Level 4 portions of the feeder.
  71. What are the most typical causes of feeder faults?
    The main causes of feeder faults include:

    • trees or branches (falling on or contacting a conductor)
    • motor vehicle accidents
    • animals and birds
    • fire
    • insulator failure
    • broken cross arms
    • snow skip (snow falling from conductors causes them to slap together)
    • ice load
    • lightning
    • pothead failure
    • UD elbow failure
    • cable failure
  72. What should a Load Operator suspect as the possible cause of a sustained feeder fault when there has been no report or evidence as to the cause of the fault?
    When there is no report or evidence as to the cause of a sustained feeder fault, a Load Operator should suspect the cause of the fault to be failure of the feeder cable.
  73. What are some typical causes of substation equipment outages?
    • Typical causes of substation outages include:
    • · Failure of the equipment itself
    • · Vandalism
    • · Underground cable faults
    • · Protection Scheme Failure
    • · Personnel working on protection
    • · Animals and birds
    • · Source outages
  74. What has BC Hydro done within their substations to help prevent animals and birds from causing equipment outages?
    Installation of animal and bird guarding in substations to protect busses and equipment from being contacted has significantly mitigated this nuisance.
  75. Where is BC Hydro’s feeder reclosing policy documented?
    Distribution Operating Order 1D-51 (Distribution Substation Feeder Reclosing Policy)
  76. How long does a Load Operator have to attempt a manual reclose on a feeder circuit breaker following a trip?
    A manual reclose by a Load Operator must be attempted within 60 second of the forced outage if the feeder is reclose permitted.
  77. How can a Load Operator determine if reclosing is permitted on a given feeder circuit?
    • 1D-51 States:
    • One reclose attempt on distribution circuits must be done unless:
    • · Live Line Permits, Assurance of No Reclose Permits, or Guarantee of
    • · No Reclose are in effect, or
    • · The circuit is a “no reclosing” circuit as defined in the Appendix, or
    • · The reclosing is being blocked because of some unusual conditions, such as extreme fire conditions.
    • The appendix of 1D-51 lists all of BC Hydro’s feeder circuits and states whether or not substation feeder reclosing is permitted. Feeders that are not reclose permitted have their CBs marked with a white “X” in AREVA.
  78. Where is BC Hydro’s distribution substation bus reclosing policy documented?
    System Operating Order 1T-29B (Distribution Substation Bus Reclosing Policy (35 kV and Below)
  79. How can a Load Operator determine if bus reclosing is permitted at a given substation?
    • The appendix of 1T-29B lists all of BC Hydro’s distribution substations and states whether or not bus reclosing is permitted. Substations where feeder bus reclosing is permitted will have the text “FEEDER BUS RECLOSING IN EFFECT” underneath their station nameplate in SCADA. However, when field personnel enter one of these substations it will trigger the station entry alarms which will replace the “FEEDER BUS RECLOSING IN EFFECT” text in SCADA with a flashing “DO NOT RECLOSE” text.
    • Substations that do not permit distribution bus reclosing will have no text underneath their substation nameplate.
  80. What is cold-load pickup?
    After prolonged outages, diversity among thermostatically-controlled no longer exists. The loading this imposes on the distribution system after a lengthy outage is referred to as Cold-load Pickup.
  81. When is a feeder outage considered to be momentary and when is a feeder outage considered to be sustained? What are the Load Operator’s responsibilities in terms of reporting?
    Momentary outages are those that last less than one minute. These outages are not required to be reported by Load Operators.

    • Outages of one minute or longer are considered to be sustained outages. For these outages the Load Operator must:
    • Enter feeder level 4 sustained outages in CROW within 5 minutes
    • Report outage to HRC
  82. How are Power Line Technicians dispatched?
    PLTs are dispatched by HRC as per DOO 1D-10.
  83. How are Station Electricians and CPC Techs dispatched?
    Station Electricians and CPC Techs are dispatched by the Control Centre. Callouts are made following the procedures outlined in SOO 1T-82.
  84. General and role-specific logging procedures can be found in what operating order?
    System Operating Order 1T-07 (Logging Procedures)
  85. What must a Load Operator first do upon assuming PIC duties?
    Upon assuming PIC duties, a Load Operator must first sign the log.
  86. When is a Switching Order required?
    When a switching instruction consists of 3 or more steps, a Switching Order is required.
  87. The Switching Order procedure is defined in what operating order?
    System Operating Order 1T-06 (Switching Procedures, Designated Isolation Point and Equipment Not Ready for Service)
  88. Where are the definitions, rules, and procedures pertaining to Safety Protection Guarantees found?
  89. Safety Practice Regulations under Section 600.
  90. In addition to recording the issue of a Safety Protection Guarantee with an SPG card, what additional logging must take place?
    On the paper desk log the SPG number, the designation of lines or equipment to which the SPG applies, and the time and date are recorded. When the SPG is returned, the Load Operator will record on the paper desk log the exact time of the SPG return.
  91. What is the purpose of POCC?
    POCC is the electronic PSSP mimic display used by the Load Desks to mimic the Level 4 main trunk of the distribution system outside of the substation fence. It was rolled out to replace the distribution wall boards of the province’s four Area Control Centers.
  92. What operating order describes the guidelines for using and updating POCC?
    Distribution Operating Order 1D-52 (POCC)
  93. What operating order describes specifically how POCC is to be used as a mimic display?
    Distribution Operating Order 1D-06 (Distribution Mimic Displays)
  94. How are reclosers and SCADA switches displayed in POCC and why?
    Reclosers and SCADA switches in POCC are displayed as blue devices. A blue device indicates that the device status must be verified in AREVA.
  95. What does the “L” symbol displayed in the POCC Schematic Window represent?
    The “L” symbol indicated a Level 4 loop extending from the main trunk.
  96. What is a composite schematic?
    Composite schematics display multiple feeders on the same schematic so that the user can easily trace between circuits when switching involves more than one feeder. Usually they are made up of all the circuits of a given substation or all circuits within a geographical area.
  97. Why is the POCC Geographic Window not used for operating in real time?
    POCC Geographic window is not used for operating in real time because it is not maintained in real time when temporary and permanent changes are made to the distribution system.
  98. How can updates be made to POCC schematics in real time? What is the preferred method of updating a POCC schematic?
    The preferable way to update a POCC Schematic is electronically with the POCC Schematic “Editing” and “Redline” tools. The second and not preferred method is to print a paper copy of the POCC Schematic, mark up the paper copy by hand, and set the electronic POCC Schematic “out-of-date”.
  99. Generally speaking, what is the purpose of the CROW application?
    CROW is used as a communication tool by the control room and field staff.
  100. What line of operating orders are the CROW guidelines described in?
    1T-54 System Operating Orders.
  101. What are the four different browsers within CROW?
    • Outage Requests
    • Events
    • Permit Requests
    • Station/Field Reclosing
  102. What is a CROW Outage Request?
    An Outage Request is a formal process by which planned work is evaluated and approved (scheduled) by Operations Support (Operations Planning and Outage Scheduling) for implementation by RTO, TNO and GMC.
  103. What must be done in CROW when an approved Outage Request is taken?
    When an “Approved” outage is taken, the outage must be “Implemented” in CROW.
  104. When should an implemented Outage Request in CROW be completed?
    A request should be completed once the “Implemented” request has been returned.
  105. What events are logged in the CROW Events Browser?
    • Forced Outage
    • Carried By
    • Unusual Condition
    • Alarm
  106. What events are logged in CROW as Forced Outages?
    • Events involving station equipment within their area of operating responsibility
    • Outage events involving sustained distribution system feeder outages and associated equipment. Momentary feeder outages will not be entered in CROW as per DOO 1D-10.
    • Events involving Bulk customers that connect to the distribution system.
    • Events involving IPP generating units larger than 20 MW connected to the distribution system.
  107. What is the general purpose for logging Forced Outages in CROW?
    • To capture availability/unavailability of equipment and circuits,
    • To record significant operating reconfigurations that impact reliability,
    • To record customer impacts, and
    • To record SDR data.
  108. What are Parent and Related Outages?
    The Initiating event is considered a Parent Outage. Outage events that occur as a direct result of another outage event are considered Related Outages.
  109. Why are Carried Bys logged in CROW?
    • The general purpose of the “Carried By” entry is to provide a means of logging abnormal feeder configurations. By logging theses abnormal feeder configurations in CROW, they can easily be filtered and viewed by Desk/AOR.
    • Another reason is that a new “Carried By” entry for a feeder will cause any permits (Live Line, Assurance of No Reclose, and Guarantee of No Reclose) that have been approved in CROW P3 for that specific feeder to be un-approved. The responsible Load Operator will be required to research these permits again and re-approve them with the appropriate reclosing requirements selected.
  110. What is an Unusual Condition?
    “A change from the normal state or condition of equipment, that impacts the operation of the system or system equipment, where it is expected to be returned to its normal state in the near future.”
  111. What operating order describes alarm handling and the criteria for entering alarms in CROW?
    System Operating Order 1T-54B (CROW Event Processing)
  112. How are AREVA analog alarms that are nuisance or may indicate failure of equipment entered into CROW?
    AREVA analog alarms that are nuisance or may indicate failure of equipment are logged in CROW as “EMS/SCADA” events.
  113. What is the purpose of the Permit Requests Browser (P3)?
    The Permit Browser is part of the “P3” functionality in CROW and is the tool used to log and track all distribution permits.
  114. What is the purpose of the Reclosing Browser?
    The Reclosing Browser compiles a list of all non-supervisory devices which require their reclosing control to be switched to the “off” position in order to support a requested permit in P3. In short, the Reclosing Browser is used to inform the field of manual reclosing requirements.
  115. What areas of the province use the Reclosing Browser?
    The Lower Mainland and Vancouver Island.
  116. Every night, after the day’s permit requests have been processed, what manual task must be performed by the Load Operator and why?
    • The responsible Load Operator will sort through the “Reclosing Browser” and update two columns:
    • Reclosing Off Required
    • Reclosing On Required

    • For each device listed on the browser, the operators will asses:
    • Auto Reclosing Current Status (On or Off)
    • Permits Pending (Yes or No)
    • Dates Required (When is Reclosing Required “Off”?)
    • By processing this information, the operator will know whether the device’s reclosing is required to be turned “on” or “off” the next day. If it is required to have a device’s reclosing turned either “on” or “off” the next day, the operator will select the appropriate box.
  117. What operating drawings are produced by DAD for use in the control room?
    • Distribution Operating Diagrams (DOD)
    • Underground Distribution Diagrams (UDD)
    • Primary Maps
  118. What is the purpose of the “Yellow Sheet Check” performed by the Load Operator?
    • The “Yellow Sheet Check” has two purposes:
    • To check that a PA has been correctly updated on DAD and matches the red mark up on the print (UDD or Primary Map)
    • To compare a new print against the current print to make sure the new one is correct
Card Set:
Load Term 2
2012-09-11 02:15:07

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