LOD

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LOD
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2014-07-24 22:10:59
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LOD
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  1. 1. What should a Load Operator always reference prior to switching in a substation?
    The Load Operator should always reference the Station Operating Order prior to operating any equipment within a substation.
  2. 2. Describe the “5 R’s” of switching.
    Readings

    • Take maximum demand and/or observed ammeter readings to determine that equipment ratings and relay settings will not be exceeded. Check the current readings (or use Max Demand) at the substation(s) on all three phases of both circuits for unusual
    • readings if switching or paralleling is within substation or on feeder cable.

     

    Ratings

    • Ratings and settings are found on station one line diagrams and protection information
    • sheets. Additional voltage regular ratings can be found in OO 2T-04.

     

    Reclosing

    Automatic reclosing must be turned off unless specified differently in other operating orders or with approval of the SCM

    Enable ground trip blocking on electronic reclosers when performing single phase switching (OO 2T-24)

     

    Series Reactors

    • Series reactors significantly affect load sharing, if their impedances differ. When switching involves breaking distribution feeder loops or parallels, the reactor impedance in each branch must be considered to determine the loop impedance and the current shared in each branch. Compare the current to the maximum current
    • interruption capability of the switch to be opened.

     

    Voltage Regulators

    When feeders fed from the same source are tied together in the substation, voltage regulators are placed in NCO (neutral position and the control circuits switched off)

     

    When feeders fed from a different source are tied together in the substation, the regulators to be paralleled should be set on different percentage taps to offset transmission differences.

     

    Same Source

    When feeders fed from the same source are tied together in the field, the voltage regulators are to be placed in manual control mode with taps on the neutral position and the control circuits switched off (NCO).

     

    When feeders from different sources are tied together in the field, leave the voltage regulators in automatic control mode
  3. What is a low-side or low-voltage tie?
    Low-side or low-voltage ties are when, during switching, Higher Voltage circuits that are normally tied together directly are tied together through Lower Voltage ties.

    Low-voltage ties can result in equipment overloads.
  4. 4. What are the two general types of isolation points? Give examples of each type.
    The two types of isolation points are conventional (disconnect switches, circuit switchers, fuses, bus links, rack-out circuit breakers) and temporary (bus cuts).
  5. 5. What must be done to an isolation point in order for it to be used in support of a Safety Protection Guarantee?
    Isolation points used to support a Safety Protection Guarantee are enforced with the appropriate Do Not Operate tags (ie. Clearance, Test & Work, or Guarantee of Isolation tags).
  6. 6. True or False – Voltage Transformer secondaries are Level 5 equipment and therefore, when located inside a Clearance zone, should be opened and tagged Self Protection to prevent backfeed prior to going to work.
    False. The isolation point must be tagged with a Safety Protection Guarantee (T&W or CL) tag. The PIC must no issue the SPG until this isolation has been completed.

    SPR 603.9 and 605.11
  7. 7. Why are gas relays opened and tagged Caution when isolating a substation power transformer?
    Gas relays are opened and tagged Caution when isolating a substation power transformer so that these relays do not inadvertently operate while working on equipment. They are blocked as part of the Safety Protection Guarantee process.

    If the gas relay is not blocked, and is accidentally bumped transfer fault isolation will operate and if there is no high side CB, a transfer trip will open the CB at the remote end of the line supplying the transformer.
  8. 8. How is a transfer bus used to maintain service to a feeder position that is coming out of service?
    When it is necessary to switch substation feeder equipment (circuit breakers, reactors, voltage regulators, disconnect switches, etc) out of service, the associated feeder’s load can be tied off to the bus-tie or standby position (or any other feeder if loading permits) through the transfer bus in the substation.
  9. 10. Where is the criteria listed for D3 switching involving series reactors?
    2T-27 lists the criteria for D3 switching involving series reactors
  10. 9. Describe how series reactors can affect load sharing when paralleling feeders.
    Series reactors affect load sharing if their impedances differ. When switching involves breaking distribution feeder loops or parallels, the reactor impedance in each branch must be considered to determine the current in each branch. This current must be compared to the maximum current interruption capability of the switch to be opened.
  11. 1. Define feeder cable.
    Feeder cable is the underground portion of a feeder that delivers power from the substation (from the substation pothead) to the first switchable device in the field. Typically the feeder’s field pothead switch but could be a switching kiosk, vista switch, vault, or junction box.
  12. 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.
  13. 3. How do cablemen request for station risers to be removed in advance of planned feeder cable work?
    Cablemen will request the risers be removed when submitting their Outage Request Form through CROW. The request will be made under “Notifications” section of the ORF in the “Comments” box addressed to the station Electrician.
  14. 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. Green – Risers removed. Black – Risers installed.
  15. 5. What is ferroresonance?
    • Ferroresonance is a phenomenon that can occur on electric circuits that contain a capacitance in series with a nonlinear saturable inductance. Ferroresonance exists when energizing and de-energizing feeder cables and voltage regulators in series with single-phase pothead disconnects or sleeves.
    • Ferroresonance is typified by unpredictable non-linear over voltages with high harmonic content and can lead to equipment damage and failure and safety issues for workers performing switching.
  16. 6. Where is the feeder cable switching procedure to be followed by Load Operators found?
    The feeder cable switching procedure to be followed by Load Operators is found in System Operating Order 2T-27 (Feeder Switching and Paralleling).
  17. 7. What must be done prior to opening pothead sleeves on a feeder cable and why?
    Prior to pulling the pothead sleeve, confirm current to be less than 2 amps to ensure that load will not be dropped or a parallel broken on the sleeve.
  18. 1. What is a standby circuit?
    A dedicated standby circuit normally has no load connected to it and will be available if needed to carry the full load of any one of the feeders it provides standby service to. A standby circuit can carry multiple feeders as long as the total loading doesn’t exceed any of its ratings.
  19. 2. How can a standby and partial standby circuits be identified on AREVA and POCC?
    • A true no-load standby circuit in AREVA and POCC is identified by placing a solid red box around the feeder text.
    • A partial standby (less than 50 amps) is designated in AREVA and POCC by placing a dashed red box around the feeder text.
  20. 3. How can maximum demand readings be used to help make operational decisions?
    Using maximum demand readings, the O/AD can take into account any expected increase in demand during the length of time that the circuits will be tied together and then make a judgement as to whether or not the tie is appropriate.
  21. 3. How can a feeder’s kVA report be used to help make operational decisions?
    When sectionalizing a feeder, the kVA report is used to know how the load is distributed along the feeder. This allows the operator to open and close switches with confidence that equipment ratings and relay settings will not be exceeded.

    Multiplying the “% kVA” by the feeder’s Maximum Demand Reading gives an idea of approximately how much load is connected beyond that device.
  22. 1. What operating prints are currently used in the Control Centre to operate and mimic the URD system?
    Underground Distribution Diagrams, Underground Distribution Schematics, or Distribution Operating Diagrams are used in the Control Centre to operate and mimic the URD system.
  23. 2. Describe a URD loop system?
    A URD loop system includes multiple feeds to provide an alternate source for the URD primary.
  24. 3. What is the normal procedure for switching on a URD loop system?
    The normal procedure on looped URD systems for non-dedicated switchgear shall be to always “break” before “make” when carrying out any switching unless testing has been done to confirm correct phasing.
  25. 4. What factors must be considered when closing a loop on the URD system and why?
    The magnitude of the loop current that could flow when closing a loop on the URD system must be considered because when paralleling circuits through the URD, loop current could be of sufficient magnitude to blow fuses or even overload URD equipment.

    It is common practice when looping different circuits together through the URD to first parallel the circuits through a hard tie. In some cases, replacing fuses with solid links prior to making a loop is necessary.
  26. Where is the Communication Protocol to be followed by the PIC and field worker found?
    The communication protocol to be followed by the PIC and field worker is found in 1T-13 (Roles and Responsibilities of the Person in Charge and Field Workers).
  27. What category of PSSP must a worker be authorized to in order to receive an SPG?
    A worker must be authorized to PSSP Category 5 in order to receive a Safety Protection Guarantee.
  28. What is a Designated Isolation Point? Where would a DIP be recorded?
    A Designated Isolation Point (DIP) is placing a Grounding/Blocking Protection Tag immediately upon receiving a SPG. It is used when equipotential grounding is not practicable at the worksite.

    A DIP is recorded on both the BCH Control Center and field workers’ SPG form. The DIP is to be the last point to have worker control removed before returning the SPG. The PIC will confirm that Grounding/Blocking Protection Tags have been removed from the DIP as the first step of switching instructions to restore the equipment.
  29. What fundamental questions must be answered by the field worker when returning an SPG to the PIC?
    When returning a SPG the permit holder is responsible to notify the PIC of the status of the equipment that was worked while holding the SPG and declare whether it is “Ready for Service” and if “Worker Protection Grounding/Bonding” is removed.
  30. What System Operating Order defines the life cycle of an SPG card?
    System Operating Order 1T-07J (Management of Electronic Safety Protection Guarantee Documents at the BC Hydro Control Centre) defines the SPG life cycle (Pending, Issued, Returned, Completed).
  31. What are the PIC’s responsibilities following the return of an SPG declared “Not Ready for Service”?
    If an eSPG is in the Returned state with equipment deemed “Not ready for Service”, the PIC will check the appropriate box on the Returned eSPG and write notes on the eSPG indicating the reason for the not ready for service condition.

    When a new eSPG is issued to make the equipment ready for service, the person who receives the SPG must be informed by the PIC about the equipment “Not ready for Service” status from the previous eSPG.

    The returned eSPG will be promoted to the Completed state as soon as the new SPG is issued to make the equipment ready for service.

    Risers removed is not ready for service condition.
  32. What are the PIC’s responsibilities following the return of an SPG with “Worker Protection Grounds Applied”?
    If the equipment is identified as “Worker Protection Grounds applied”, the PIC will check the box on the eSPG.

    If Worker Protection Grounds are in place with no SPG in effect for equipment represented on the electronic mimic display, the PIC will place a removable Field Ground device symbol within the isolated zone and tag it with a GROUNDED tag or place a GROUNDED tag on at least one of the devices associated with the isolated zone (the tag will include the returned SPG number)Only one Field Ground device symbol should be placed per returned SPG.

    If the isolated zone is displayed on more than one display place it where the majority of isolating points and/or the normal source of energization are displayed.

    If Worker Protection Grounds are in place with no SPG in effect for equipment not represented on the electronic mimic display, the PIC will place an equivalent GROUNDED tag on the paper mimic display with reference to the returned SPG.

    The eSPG will be kept in the Returned eSPG file.When a new SPG is issued on the same equipment in the same location, the person who receives the SPG must be informed by the PIC that the Worker Protection Grounds have been left on from the previous SPG.

    The GROUNDED tag must be removed at that time and the eSPG card promoted to the Completed state.
  33. What are the PIC’s responsibilities following the return of an SPG with phasing requirements?
    Whenever phasing is required, the PIC will place a Not Available tag on the electronic mimic display describing the phasing requirement. When a Not Available tag has been placed, the eSPG may be promoted to the Returned state. The Not Available tag will be removed once the phasing is completed successfully.
  34. What is a Guarantee of Isolation and how is a GOI recorded?
    A Guarantee of Isolation (GOI) is a means of effecting guaranteed isolation between different Operating Authorities. The PIC who issues or receives a Guarantee of Isolation shall use a Safety Protection Record form to record the conditions established.
  35. 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 Transfer of Operating Authority (TOA) is a procedure between adjacent PICs to move an operating boundary such that the required lines or electrical and mechanical apparatus are all within one area of control following the transfer.SPG cards are not required when Operating Authority is transferred within the control room.

    SPG cards are used to record the transfer between PICs at different control facilities.
  36. What category of PSSP must a worker be authorized to in order to receive a Live Line Permit?
    A worker must be authorized to PSSP Category 5 in order to receive a Live Line Permit.
  37. What category of PSSP must a worker be authorized to in order to receive an Assurance of No Reclose Permit?
    A worker must authorized to PSSP Category 4 in order to receive an Assurance of No Reclose Permit.
  38. What is a Guarantee of No Reclose?
    A Guarantee of No Reclose is 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.
  39. 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 is used to log the issuing and returning of Live Line Permits, Assurance of No Reclose Permits, and Guarantees of No Recloses. Requests made and processed in real time are logged on the paper log.
  40. What is the purpose of a CNE?
    A Commissioning Notice to Energize (CNE) is required to energize new substation equipment. The CNE authorizes the Operating Authority to proceed with the initial system energization tests of electric system plant additions, modifications, and replacements.

    On completion of the CNE signoff, the equipment or circuit shall be part of the Power System under BCH Contro lCentre Operating Responsibility.
  41. What part of the power system requires a CNE for the commissioning of equipment?
    Substation equipment which impacts Station Operating One-Line Diagrams up to the feeder-cable terminations and overhead-feeder connections require a CNE for the commissioning of equipment.
  42. 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?
    Following the completion of a CNE, and the electronic PSSP Mimic Display is not ready for upload to reflect the changes to the system, the PIC will set this condition by clicking on the “PSSP Mimic Display” text to poke the “Check Paper One-line” red button. This will enable dynamic yellow text to flash and display “CHECK ONE-LINE”.
  43. What is a Plant Alteration?
    A Plant Alteration (PA) is the addition or removal of high-voltage (less than 60kV) plant on the distribution system. PA’s ensure that all parties responsible for the operation of the power system maintain accurate and up-to-date operating drawings and mimics. All changes to the distribution system, which impact the operating records, require a PA.
  44. What part of the power system requires a PA for the addition and removal of plant?
    A PA is required for the addition and removal of plant on the distribution primary from the feeder-cable terminations and overhead-feeder connections in the substation outward.
  45. What is the purpose of the PA process and what operating order is the process defined in?
    The Plant Alteration 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. All changes to the distribution system, which impact the operating records, require a PA.

    The PA process is defined in DOO 1D-01 (Distribution Plant Alteration and Operating Drawing Updates).
  46. What is PAT?
    The Plant Alteration Tracking (PAT) system is the computer program used to track the progress of a PA from the time it is issued through the time it is completed and the new drawings have been updated, approved, and issued.
  47. What is the role of the PA Coordinator?
    The PA Coordinator is responsible for managing the PAT tool.

    The PA Coordinator will print a hard copy of the new PA and attach a PA cover sheet to it and file the PA in the PA filing cabinets in the control room.

    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.
  48. When working on a PA to install a new underground loop connection, at what point is a Safety Protection Guarantee required?
    A Safety Protection Guarantee (SPG) is required prior to the termination of the cable at either end that will serve to create a loop on the system.
  49. What are the Load Operator’s responsibilities following the completion of a PA?
    The Load Operator must access the PA and determine what operating drawings and operating tools have been impacts. They must update all operating diagrams and POCC in real time to reflect the system accurately. Changes to paper drawings will be initialled and dated by the operator.

    When a PA is completed, the operator will sign off, date, and note the name of the electrical worker completing the PA and make any new drawing requests on the cover sheet.
  50. What is a PACTOR?
    Protection, Control and Telecom Operation Report (PACTOR) lists all equipment or items including any deficiencies after installing and testing of a protection, control and telecommunications system (or part of a system).

    After receiving a Protection, Control and Telecom Operation Report (PACTOR), FVO will authorize to place protection, control, and telecommunications systems in service.
  51. Protection, Control and Telecom Operation Report (PACTOR) lists all equipment or items including any deficiencies after installing and testing of a protection, control and telecommunications system (or part of a system).
    When protection, control, and telecommunication equipment is commissioned concurrent to power system equipment then a CNE should be used and a PACTOR is not required in addition to a CNE.

    All field devices must be added to the system under the Plant Alteration (PA)process outlined in DOO 1D-01.

    A PACTOR document is required by the Control Center for upgrading amanually-controlled device to have supervisory functions. Additionally, any revised operating orders (if necessary) are also required prior to placing equipment in service.
  52. Briefly describe the process for commissioning a brand new field recloser with supervisory control.
    • 1) A PA is required for all new installations with the lead-time specified in DOO 1D-01 to allow the control centre to update all necessary databases.
    • 2) Prior to energizing for the first time, the Power Line Technician (PLT) will contact the associated control centre and quote the PA number.
    • 3) Prior to allowing the device to be put in service, the control centre must add the device to the CROW (P3) database and the official mimic display. Refer to OO 1T-54D Appendix #3.
  53. What is a Declaration of Compatibility?
    A Declaration of Compatibility form  must be provided to the Control Centre that states the IPP has full responsibility for the inspection, testing, and calibration of its equipment, up to the Point-of-Interconnection.

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