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With respect to generating station step-up transformer, what protective relays are in place to detect fault conditions? Name both electrical protection and non-electrical protection.
- Differential relay (87) detect windings and thermal faults. A current transformer is installed at each terminal of the protected equipment to measure the current going in and the current going out. A relay is connected so it sees only the difference in in the currents.
- Ground differential protection. Detects an earth fault in the winding.
- Gas relays (63) detects the slow accumulation of gas which may be given off by a developing fault.
- Sudden pressure relays (63) detects a violent disturbance of pressure resulting from a developed fault
- Conservator low oil device
- Oil temperature
- Winding temperature
- Pressure relief devices relieve pressure in the transformer tank should a fault occur.
Describe the importance of detecting a field ground on a synchronous generator. What are the consequences of two field grounds on a synchronous generator? Which protective relay
- detects field grounds?
- Detecting a field ground on a synchronous generator is important because the field winding must produce symmetrical magnetic flux, otherwise the resulting machine unbalance will cause shaft deflection and vibration.
Loss of symmetrical field can be caused by short-circuiting of a portion of the field winding. The short-circuiting causes overheating of the field winding. Unit vibration detectors and field overtemperature detectors protect against these conditions.
- Two field grounds on a synchronous generator will cause a short-circuit unbalance.
- A protective relay (64) provides protection for field grounds.
What is meant by the term “loss of field” with respect to the operation of a synchronous generator? Describe the importance of detecting loss of field. Which protective relay detects loss of field? What facility is in place on some synchronous generators that prevents the operator or the AVR from reducing excitation below the pickup value for Loss of Field protection?
- “Loss” of field is when the generator loses excitation.
- Loss of excitation causes the generator to:
- • Draw reactive power from the system (requirements might exceed capabilities of nearby sources)
- • Voltage disturbance to the system
- • Overloading of stator and overheating of rotor
- • Machine will operate out of synchronism. The rotor will oscillate in an attempt to lock into synchronism. Large reactive currents may cause large induced current in the stator (stator overheating)
- • Generator still supplies the same power to the system
- A protective relay (40) detects the loss of field. A compound relay that includes:
- Directional unit, closes its contacts when reactive power flows into machine
- Offset Impedance element closes its contacts when the impedance of a machine is below a pre-determined value
- Undervoltage element
MEL (minimum excitation limiter) prevents loss of excitation to the machine in normal excitation control.
What is a Remedial Action Scheme? What is its purpose?
- Remedial Action Scheme (RAS) is:
- An automatic protection system designed to detect abnormal or predetermined system conditions, and take corrective actions other than and/or in addition to the isolation of faulted components to maintain system reliability. Such action may include changes in demand, generation (MW and Mvar) or system configuration to maintain system stability, acceptable voltage, or power flows. An RAS does not include:
- • Underfrequency or undervoltage load shedding
- • Fault conditions that must be isolated or
- • Out-of-step relaying
- The purpose of the RAS actions is to mitigate an undesirable effect of the contingency on the power system such as,
- • “AS” means to preserve angular stability, or to limit the magnitude of voltage swings to acceptable levels.
- • “F” means to control frequency within acceptable levels
- • “OL” means to prevent thermal overload
- • “VC” means voltage control
What is the most typical RAS scheme? What is its purpose?
- The most typical type of RAS is Gen Shed.
- The purpose of Gen Shed is to maintain angular stability of the bulk electric system by generator shedding or immediate disconnection. This action reduces the amount of power from what was previously transmitted through a certain part of the network following a transmission contingency. Genshed is required to maintain angular stability of the bulk transmission system.
How is Generation Shedding armed? How are Plant Operators made aware of generation shedding being armed?
- Arming of Generation Shedding is done through the Energy Management System Advanced Application, TSA-PM, and is the responsibility of the Transmission Coordinator.
- Plant Operators are made aware of generation shedding by a flashing “c” which means shedding has been armed for a contingency.
What alarms may be received on a Gen Shed operation? What is your response to units tripping from Gen Shed operations?
- For a Gen Shed operation the alarms will typically come in at the same time as the unit breaker alarm and may look like:
- • Gen Dump Received (SEV, MCA, REV)
- • LATEST_ACTXX (KCL), where XX is the unit #
- Plant Operator should be able to discern if the unit tripped because of genshed.
- When a generator breaker(s) has opened due to gen shed and the station has remained in synchronism with the system, the unit(s) shall be synchronized to the system as soon as possible. (Except KCL which must be approved by the TC).
- The GC should be called for loading instructions. The LFC or AGC should remain OFF until GC approval. If the GC is busy or does not need the output, units should be loaded to 10%.
- If there a customer outage that requires a generator to serve local area load, the Plant Operator must independently initiate a generator start sequence within 2-3 minutes of the initial trip. Grid/Load Operator must be advised and their permission is required to restore load.
What Operating Order documents Station Alarms policy?
1T-38 documents the procedures for alarm handling by BC Hydro Control Centres.
What is the primary difference between station alarms and analog alarms?
- Station alarms for BC Hydro operated generating stations alarm at the generating station and are telemetered to the BCH control centers where they are processed by EMS through the alarm application.
- Analog alarms are generated solely at the BCH Control Center EMS, through the alarm application.
Who determines the priorities for alarms at BC Hydro Generating Stations? In which document can you verify the alarm priorities for SEV generating station?
- BC Hydro Generation Line of Business (GLoB) determines the priority of generating station alarms, unless the alarm has an impact of transmission system reliability. RTO accepts and approves alarm priority provided by GLoB.
- Station alarms are documented in station Local Operating Orders.
- 3G-SEV-02 has the alarm priorities for SEV generating station.
What are the priorities and appropriate response for all generating station alarms?
- Priority 1: Auto operations alarms ie breaker/disconnect status change
- Priority 2: Analog Alarms. Dispatcher action required. Analog alarms are not to be entered in CROW.
- Priority 3: Urgent alarm requiring immediate maintenance response. Must call field staff and enter in CROW.
- Priority 4: Semi-urgent alarm. Callout between 08:00 and 22:00, 7 days a week. Must call field staff and enter in CROW.
- Priority 5: Non-urgent alarm requiring next working day response. Enter in CROW only. No need to call field staff.
- Priority 6: Information messages. No need to call staff for all priority 6 alarms. No requirement to enter in CROW unless entry disable alarm is still up during the night.
- Priority 7: Nuisance alarms are moved to priority 7
- Priority 8: unused (spare)
T or F – Priority of an alarm may become higher based on other associated alarms that come in at the same time.
True (example 1T-38 Appendix section 2.6.
What is the primary difference in callout procedures for emergency situations versus non-emergency conditions at BC Hydro generating stations?
- In an emergency situation (public health and safety, reliability of the transmission system, limit or prevent damage to property or the environment or expedite restoration service) the operator will first call crews by following the callout list (COPS) and call the standby manager at the first opportunity.
- In a non-emergency situation the standby manager will be called first.
What can single generating unit trips be caused by? What is the Plant Operators response?
- Single unit trips can be caused by:
- • Generator protection operations
- • Generation shedding
- The Plant Operator must:
- • Respond to any water flow issues while adhering to ramp rates and minimum flows
- • Aid the Generation Coordinator in replacing generation (if required).
- • Aid the Transmission Coordinator/Grid Operators in any voltage issues that have resulted
- • Investigate the cause of the outage, report the outage to PSOSE and the BC Hydro Plant Manager (Standby Manager after hours) and log in CROW.
- If the unit outage was caused by gen shed, the Plant Operator should re-synchronize the unit but not load until directed by the TC or GC.
- If the unit outage was caused by a protection operation, the outage should be discussed with the Plant Manager (or standby manager if after hours) regarding investigation based on the alarms received.
What can multiple generating unit trips be caused by? What is the Plant Operators response?
- Multiple generating unit trips can be caused by:
- generation shedding
- protections at the station other than the individual generator protection
Similar to single unit trip, except the disturbance on the system may be much larger. The Plant Operator should be readily available to support the Generation Coordinator, Transmission Coordinator, and the Grid Operator to ensure the reliability of the bulk electric system.
What is an islanding event? What can the Plant Operator expect to happen in an islanding event?
- An island is defined as a pocket of generation and load operating at a given frequency.
- Plant Operators should expect Transmission Coordinator, Generation Coordinator, or Grid Operator to make them aware that no generation changes should be made without their approval including changes to generation for water reasons.
What is blackstart? When may a Plant Operator be asked to blackstart a generating station? What is the typical blackstart procedure?
- Blackstart is the starting of a generating unit without an external source of station service. Blackstart operations are the first step in restoration activities when a disturbance has de-energized a large area of the bulk electric system. The Plant Operator will perform blackstart of a generating station as directed by the Transmission Coordinator, Generation Coordinator, or Grid Operator.
- A typical blackstart procedure is:
- • Obtain a source of station service (usually local diesel generation)
- • Put an auto-start on the units
- • Open all generating station switchyard CBs
- • Close generator unit CBs to energize the step-up transformer
- • Synchronize enough generators to one another as directed by the System Operator
Where does BC Hydro have remote blackstart capability?
What are the typical types of Environmental Incidents?
- Environmental Incidents caused or have the potential to cause:
- • Adverse impact on the quality of air, land or water, wildlife, aquatic species or species or species at risk
- • Exceedence of permit or external reporting requirement
- • Notification of external agencies due to emergency/beyond normal circumstances
- • Adverse publicity with respect to environment
- • Legal or regulatory action with respect to violation of statues or environmental damage.
- • Alteration of, or damage to, heritage or archaeological resources
What is the only type of Environmental Incident the Plant Operator is responsible to report?
The Plant Operator has to report all environmental violations relating to water conveyance to PSOSE and the System Control Manager.
What is a Water Conveyance instruction? Who typically initiates all Water Conveyance instructions?
- Water conveyance is synonymous with operations of Non-Power release facilities (NPRF). A water conveyance instruction is a real time operation of NPRF based on specific operating directions from Outage Planning Engineers, applicable Operating Orders, water licenses and environmental restrictions.
- PSOSE typically initiates all Water Conveyance instructions. Plant Operator will access the instruction for known plant constraints and either accept or reject the instruction before it times out.
Where are all Water Conveyance instructions recorded?
Water Conveyance instructions are recorded in Commercial Management (CM).
Who maintains Operating Responsibility of SEV generating stations NPRFs? Why?
BCH T&D has Operating Responsibility of SEV generating stations NPRFs. Typically, all NPRF that can be operated remotely from BCH Control Center will have Operating Responsibility assigned to BCH T&D. Operating Responsibility of all local only NPRFs is maintained by Generation.
Can a BC Hydro Control Centre operator operate a NPRF facility without first notifying PSOSE? What must be done if the operation is done without a Water Conveyance instruction?
- An Operator can operate NPRF without an instruction from PSOSE when:
- • Flood routing
- • Dam safety related operation
- • Maintaining a steady forebay (eg. SEV or COM)
- • Managing discharge for downstream tidal influences
- The Operator records details of NPRF operations that were not initiated by PSOSE in the Water Conveyance Implementation Creation screen.
What is the purpose of the paper based log?
To keep a record of system events ordered or observed by Operators for proper archiving and analysis of these events.
What types of details are recorded in the paper based log?
- Details on the paper based log include:
- • Switching Order Forms, Safety Protection Guarantee (SPG) forms (not the Plant Desk)
- • Operating Responsibility assigned to BCH generating station personnel
- • Anything not captured using electronic logging in the General Events section including reasons for making decisions or doing certain things if they are not in CROW
- • Critical tasks that crosses shifts
- • Entry/exit and manchecks
- • Critical water levels and callout information
What are the operators and apprentices responsibilities associated with the paper based log?
Operators and apprentices must sign on to the log for their shift. Signing on to the official log for a desk is required to assume the shift duties for that assigned portion of the power system associated with that operating desk. All RTO Desks requiring PIC duties must have an Operator signed on as PIC at all times.
What does SCADA stand for? Explain SCADA.
- Supervisory Control and Data Acquisition (SCADA) monitors, controls and alarms plant or regional electric systems from a central location.
- • SCADA is at substations and generating plants to provide supervisory control of switchyard equipment, generators and spillway facilities from FVO/SIO.
- • Provides telemetry (kV, Amps, MW, MVar, and MVA) from the facilities to the Control Centers.
- • Sends alarms from the substation back to the Control Center when equipment changes status or violates a limit.
- SCADA is a part of the larger Energy Management System (EMS).
What are the four key functions of SCADA? Define each.
- Telemetry: Communication of data over a communication channel, in this case from Remote Terminal Units (RTU) at the station to the Control Center.
- Status Reporting: Reporting of the change of status of a device at a remote facility. Status of supervisory control points is communicated via communications channels to the Control Center via the RTU.
- Alarm Reporting: Alarms are generated at a substation for certain conditions that do not require status indication. When a piece of equipment goes into “alarm”, the corresponding alarm point is communicated via communication channels to the Control Center RTU.
- Remote Control (or supervisory control): allows the operation of devices at remote facilities.
What are the three major components of a SCADA system? Define each.
Master Station: Computer with the input/output equipment needed to transmit control measures to the remote units and to receive information from them. Remote operator initiated operations of a RTU are made through the master unit and reported back to the master from the RTUs. If successful, the RTU will report back the status change (will also report back if unsuccessful).
- Remote Terminal Units (RTU): When the master unit makes a command, the RTU will send commands to the appropriate device to make the requested change. RTU will report back the status change if the control is successful.
- Transducers in the RTU convert quantities such as voltage and current to DC or voltage for communication to the Control Centres.
- Communications: Signals between the Master Station and the RTUs are sent across communication facilities for supervisory control, telemetry and alarm reporting (typically microwave communication). Microwave signals utilize microwave towers and repeater stations and are redundantly reliable so they are preferred.
- Power Line Carrier uses the transmission lines between two stations as the communication path. A medium range frequency signal is put on one phase of the line that does not interfere with power transfer. It is less reliable due to the fact if the phase were to become grounded, communication is lost.
What is the purpose of CM? Who is the owner?
- Commercial Management (CM):
- • Stores data and provides processes for managing generation capabilities, dispatchable generators and planned maintenance outages
- • Provides information for those managing, maintaining and operating power plants
- • Provides a clear record of water conveyance via NPRFs.
- BCH Generation LOB is the owner.
What is the Plant Operators responsibility with respect to CM?
- The Plant Operator must:
- • assess SENT instructions for known plant level constraints and then accept or reject the instruction before it will time out (30 minutes).
- • implement directly the instructions for supervisory controlled NPRFs or by the Operator instructing Power Facility personnel to operate local controlled NPRFs on-site
- • record in CM all implementation details associated with ACTIVE instructions and complete
- • Record details of NPRF not initiated by PSOSE using the Water Conveyance Implementation Creation Screen
- • Implement or Complete any planned outages and enter any forced outages into CM
What is the purpose of DCM? Who is the owner?
- Grid Operations Dispatch and Compliance Monitoring (DCM) enhances the ability of Grid Operations to electronically interact will all transmission market participants in a consistent, transparent, non-discriminatory and auditable manner.
- Grid Operations is the owner.
What is the Plant Operators responsibility with respect to DCM?
- The Plant Operator will verify that the operation does not create a known safety, environmental or plant equipment risk, and is responsible to ensure that accepted operations are made accurately and quickly to achieve the desired output from a unit.