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What is WPP? Where is it used?
WPP is the Work Protection Practices. They are the rules and guidelines that apply to all work performed on equipment in Integrated Generation facilities for which hazardous sources of energy must be isolated and locked out for worker safety.
How are PSSP/WPP boundaries identified?
- On the station one-line diagram and defined in a joint local operating orders having the following minimum content:
- Identification of equipment for which WPP or PSSP is in effect
- Reference to this operating order for operating proceduresAny specific requirements not addressed by or exceptions to this operating order
Who holds Operating Authority for the PSSP equipment at Integrated Generating Stations?
BCH T&D Control Centre
Who holds Operating Authority for the WPP equipment at Integrated Generating Stations?
On-site Generation staff
What is the procedure for establishing work protection for equipment identified on the station one-Line, located on the WPP side of the WPP/PSSP Boundary? Give an example.
- For switchyard equipment, the Operator at the Control Centre will assign Operating Responsibility up to and including the appropriate one-line perimeter isolating devices without directing the switching of the electrical isolating devices to an authorized category “D” worker on site.
- The on-site worker will then assume the role of PIC. The WPP PIC will open and lock the perimeter one-line isolating devices as required.
- Alternatively, the Operator at the Control Centre may direct switching to isolate the equipment. This switching is done to ensure system security rather than facilitate work protection. In this case the Operator at the Control Centre will direct switching of the one-line perimeter isolating devices that isolate the equipment from the electric system energy sources.
Following the switching the Operator at the Control Centre will verbally assign Operating Responsibility of the isolated equipment up to and including the perimeter one-line isolating devices to an authorized category “D” worker on site. “Internal” sources such as VT’s and Station Service secondaries, etc. will be isolated by the on site PIC as required.
What are the two acceptable methods for work on equipment in the WPP area that requires isolation in the PSSP area? Give an example of each explaining when each would be used?
- Using GOI procedures:
- The Control Centre PIC can issue a Guarantee of Isolation (GOI) to the WPP PIC on the PSSP area isolating devices.
- Using Transfer of Operating Authority procedures:
- If the PSSP isolation device is within the generation switchyard then the Operator at the Control Centre can transfer Operating Authority up to and including the isolating devices in the switchyard to a worker on site authorized to category “D” using the procedures found in Appendix II of 1J-18. The on-site worker will then assume the role of PIC and is responsible for establishing work protection according to standard WPP procedures.
What are the two acceptable methods for work on equipment in the PSSP area that requires isolation in the WPP area? Give an example of each explaining when each would be used?
- Using PSSP procedures:
- The WPP PIC can issue a GOI to the Control Centre PIC on the WPP area isolating devices, following receipt of Operating Responsibility. The work can then be done using PSSP procedures.
- Using WPP procedures:
- If the PSSP isolation device is within the generation switchyard then the Operator at the Control Centre can transfer Operating Authority to a worker on site using the procedures found in Appendix II of 1J-18. The on-site worker will then assume the role of PIC and is responsible for establishing work protection according to standard WPP procedures. If a GOI is required on remote PSSP area isolating devices to perform this work then it can be issued by the Operator at the Control Centre using GOI procedures.
Who retains Operating Authority for SPN NPRF facilities?
Columbia Basin Generation
Who retains Operating Authority for SEV NPRF facilities?
What is the process for assigning Operating Responsibility to a category “D” authorized worker for SEV SPOG01?
When work is required on a NPRF under the Operating Responsibility of T&D, Operating Responsibility is assigned to the category “D” authorized worker in a similar process as used for generators. Operating Responsibility is transferred up to and including the NPRF device (e.g. SEV SPOG01).
Who retains Operating Authority of station service facilities at BC Hydro integrated generating stations?
Operating Authority of Station Service facilities is typically retained by the associated generation region.
What is the procedure for assigning Operating Responsibility of station service facilities at generating stations?
- For station service equipment, the Operator at the Control Centre will assign Operating Responsibility up to and including the appropriate one-line perimeter isolating devices without directing the switching of the electrical isolating devices to an authorized category “D” worker on site.
- The on-site worker will then assume the role of PIC. The WPP PIC will open and lock the perimeter one-line isolating devices as required.
Following the switching the Operator at the Control Centre will verbally assign Operating Responsibility of the isolated equipment up to and including the perimeter one-line isolating devices to an authorized category “D” worker on site.
What is the process for assigning Operating Responsibility to a category “D” authorized worker for work on JOR SS1?
The Control Centre Operator will assign Operating Responsibility of SS1 up to and including 25DSS1 after station service has been transferred and 25DSS1 has been opened by the Category “D” worker.
What is the purpose of protection?
To react to disturbances, eliminating or reducing their damaging effects to electrical apparatus.
What is the difference between a protection system and a protection scheme?
Each individual protective arrangement is known as a “protection system”, while the whole coordinated combination is known as a “protection scheme”.
With regards to protective relaying, what is meant by the term – Selectivity?
Selectivity means that only a minimum portion of the power system should be disconnected to isolate a fault.
With regards to protective relaying, what is meant by the term – Security?
Security refers to the fact that schemes must be able to discriminate between signals which require action, and those that do not.
With regards to protective relaying, what is meant by the term – Reliability?
Reliability is the protection’s ability to operate without failure whenever a fault or abnormal condition exists.
With regards to protective relaying, what is meant by the term – Coordination?
Coordination means schemes must relate to each other so they operate in the right order.
Provide two reasons why two sets of redundant protection are used on a piece of equipment. What are they named?
Two sets of protection gives additional dependability as well as maintained protection when one set is out for maintenance. One set is called primary protection while the other is called standby protection.
Typically in a fault condition, _______ will rise while _____ falls.
What are the two main reasons for utilizing instrument transformers?
To provide useable quantities of voltage and current for metering as well as protective relays.
What is a VT? What purpose does it serve? What is its typical output?
A voltage transformer’s (VT) purpose is to provide relays, meters and control circuits with a low voltage proportional to that of the system. Typical output is 120V.
What is a CT? What purpose does it serve? What is its typical output?
A current transformer’s (CT) purpose is to provide relays, meters and control circuits with a low current proportional to that of the system. 5A is the typical output.
If a CT has a ratio of 2000:5, what is the primary current if the secondary current is 2.5 amps?
2.5A x 2000/5 = 1000A
With respect to a CT, what is burden? How does exceeding the burden impact the operation of a CT?
Burden is the amount of load connected to the secondary of the CT and is expressed as an ohmic value. If the burden connected to the CT is too high there is a risk the CT could saturate. Once the CT saturates it can no longer accurately reflect system current.
With respect to a VT, can the secondaries be opened with the VT energized? Explain any consequences.
Energized VTs may have their secondaries open circuited. The only consideration is what protective relays are utilizing the voltage reading from the VT, and which purpose do they serve.
With respect to a CT, can the secondaries be opened with the CT energized? Explain any consequences.
Energized CTs must never have their secondaries open circuited (no burden on CT). Extremely dangerous open circuit secondary voltages may result that could potentially harm workers and/or equipment.
What is a protection zone? How is it typically defined?
The section of the power system that a particular protection covers is referred to as the protection zone.
Protection zones are usually referred to by the system they protect. Since most relays monitor current, the boundaries of a protection zone are usually determined by the location of the CTs.
What is a tripping zone? How is it typically defined?
A tripping zone is the section of the power system that is tripped by protection.
With respect to protection, what is meant by the term overlap?
To prevent the possibility of unprotected areas and to provide backup, protection zones are typically overlapped. For example, when a transformer protection zone overlaps with a generator protection zone one can act as a backup for the other. If there is a fault in the generator zone and its protection does not react, the transformer protection would then operate instead.
What is breaker fail protection?
If the Generator Zone protection senses a generator fault and initiates a protection operation but the circuit breaker does not open, Breaker Fail protection operates to trip the adjacent zone. Breaker Failure protection initiates tripping if fault current is still flowing through the breaker after a time elapses following the protection zone operation.
What are NEMA device numbers? Identify the following:
5, 12, 32, 38, 40, 41, 43, 49, 50, 51, 59, 63, 65, 79, 86, 87
- a. 5 - Stopping device
- b. 12 - Overspeed device
- c. 32 - Directional power relay
- d. 38 - Bearing protective device
- e. 40 - Field relay
- f. 41 - Field circuit breaker
- g. 43 - Manual transfer or selector device
- h. 49 - Machine or transformer thermal relay
- i. 50 - Instantaneous overcurrent relay
- j. 51 - AC timed overcurrent relay
- k. 59 - Overvoltage relay
- l. 63 - Pressure switch
- m. 65 - Governor
- n. 79 - AC reclosing relay
- o. 86 - Lockout relay
- p. 87 - Differential relay
What is the purpose of relay targets?
To provide a record of a protective relay system’s operation.
What are symmetrical components? What is meant by positive sequence? What is meant by negative sequence? What is meant by zero sequence?
Symmetrical components are commonly used for analysis of three-phase electrical power systems. If the phase quantities are expressed in phasor notation using complex numbers, a vector can be formed for the three phase quantities.
- Positive sequence means the current and voltage has a positive phase rotation (i.e. A, C, B). Each phase is equal in magnitude with an angle of 120o between them. Under balanced conditions only positive sequence exists.
- Negative sequence quantities (figure 7) may exist in addition to positive sequence if conditions become unbalanced due to unbalanced loads or a fault. An unbalanced load or fault produces unbalanced currents. These unbalanced currents produced unbalanced voltage drops through the line resulting in unbalanced voltages. Negative sequence voltages and currents are similar to positive sequence except that rotation is negative (i.e. A, B, C).
If conditions are unbalanced and there is a path to ground, positive, negative and zero sequence quantities in addition to positive and negative sequence quantities will exist. In the case of zero sequence, the phase quantities are equal in magnitude and in phase.
What two relays are used to detect stator phase to ground faults?
- Zero-sequence overvoltage relays
- Third harmonic voltage differential relays
What relay is used to detect stator phase to phase faults?
Differential Relay (87)
With respect to overspeed of an electrical generator, how is the unit protected?
Over-speed conditions often result from loss of load. Upon load rejection, the unit will accelerate since the mechanical input power is greater than the electrical output power. The governor will respond to limit over-speed. Over-speed tripping (12) is provided by centrifugal speed switches or permanent magnet generator which initiates a trip of the generator to bring the unit to a speed no load condition should the governor fail to limit the over-speed.
With respect to motoring of an electrical generator, how is the unit protected? Are there any exceptions?
Motoring occurs when the prime mover input is lost and the generator will take power from the system. A reverse power relay (32) is used to detect power flow into the generator and initiate tripping. Of course this relay is blocked if the unit is operating in synchronous condense mode.
Define 5A – Non-Lockout Partial Shutdown to SNL With Overspeed
- This function operates for conditions which are external to the machine and which will be removed once the transformer breaker has been opened. It also operates when the transformer breaker may be accidentally tripped. This relay executes the following:
- Perform non-lockout trip of breaker
- Trip field breaker
- Bring machine to speed-no-load (unit is to be shut-down)
- The 5A is operated by:
- Pole slip detector
- Stator overvoltage
- Negative sequence overcurrent
5B – Non-Lockout Partial Shutdown to SNL Without Overspeed
- This function shuts down the unit but the unit transformer breaker is not locked out; the machine can be immediately started and put back into service. This relay executes the following:
- -Initiate 10-second gate closure (i.e., shut-down unit)
- -Perform non-lockout trip of breaker when gates pass the speed-no-load position
- -Field shutdown by field gating when machine gates reach the speed-no-load position (field breaker is not to be tripped)
- The 5B is operated by:
- -Incomplete starting sequence
- -Electrical switch
5C – Non-Lockout Unload Trip Without Overspeed
- This function is intended primarily for non-urgent tripping, which allows slow unloading of the machine to permit load transfer to other machines. The machine is separated from the system but not shut down. To bring the machine from full load to speed-no-load requires approximately 30 seconds. This relay executes the following:
- -Slowly unload the machine to speed-no-load, and then trip the unit breaker (non-lockout)
- The 5C is operated by:
- -Stator over temperature device 49G
- -Reverse power relay device 32G
86N – Normal Lockout Shutdown
- Protection tripping through this device will be for conditions that require maintenance but do not require emergency shutdown. This relay executes the following sequence:
- -Initiate 10-second gate closure (i.e., shut down unit)
- -Lock out trip when gates pass the speed-no-load position
- -Inhibit field gating (field breaker is not to be tripped) upon tripping of the unit breaker.
- The 86N is operated by:
- -Loss of field protection and timer
- -Stator guard protection
- -Field over-temperature
- -Neutral resistor over-temperature
- -Field ground protector
- -Shaft vibration
- -Intake gate drop
- -Bearing over-temperature
- -Turbine bearing oil level
- -Governor sump tank oil level
- -Governor pressure tank oil level
- -Governor pressure tank oil pressure
- -Actuator lock with over-speed
86G – Generator Primary Lockout Shutdown
- The primary lockout shutdown initiates the fastest possible shutdown of the machine. It is operated only when the primary relay detects a major internal failure within the machine. This relay executes the following sequence:
- Lockout trip breaker
- Trip the unit field breaker
- Initiate 10-second gate closure (i.e., shut down unit)
- Initiate the fire protection (water spray) if fire detection equipment has operated.
- The 86G is to be operated by primary generator differential and splitphase protection.
86GS – Generator Standby Lockout Shutdown
- This shutdown executes the same functions as the 86G, except that initiation of the fire protection is not required. The 86GS is operated by:
- Exciter transformer overcurrent
- Exciter transformer overtemperature
- Loss-of-field with undervoltage
- Breaker failure protection
- Control power failure
- Fire protection power failure
- Incomplete field flashing sequence
- Cooling fan failure
- Mechanical overspeed
- Emergency shutdown push-button
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.
- Electrical Protection:
- i.Differential Relays for short circuits (i.e. Current differential relaying)
- ii.Ground Differential Protection for ground faults
- Non-electrical Protection:
- i. Gas relays (device 63)
- ii. Sudden pressure relays (device 63)
- iii. Conservator low oil device
- iv. Oil temperature
- v. Winding temperaturePressure relief devices
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?
The field winding must produce symmetrical magnetic flux, otherwise the resulting machine unbalance will cause shaft deflection and vibration. Loss of the symmetrical magnetic field can be caused by short-circuiting of a portion of the field winding. The short-circuiting of these turns will also cause overheating of the field winding.
Two ground faults in the field winding will cause a short-circuit unbalance. Thus, it is important to detect a ground on the field winding before a second one occurs. The most common method used to detect field grounds is the injection method. A protective relay (device 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 in reference to a situation where the exciter current of a generator is too low to produce a magnetic field strong enough to keep a unit synchronized with the system.
- When a generator loses excitation, it draws reactive excitation from the system.
- Possible effects of this are:
- -Voltage disturbance to the system Reactive power requirements exceeding capabilities of nearby sources
- -Overloading of stator and overheating of rotor (NOTE: generator will continue to supply power to system)
- -Machine will operate out of synchronism; thus rotor oscillations will result in an attempt to lock into synchronism. Large reactive currents may cause heavy induced currents in rotor iron (stator heating)
- Since the underexcited operation of the generators is potentially dangerous to the machine, protection must be provided to detect the loss of excitation. Protection is covered by a protective relay (device 40).
The Minimum Excitation Limiter (MEL) is put in place to prevent the operator or the AVR from reducing excitation below the pickup value for Loss of Field protection. It keeps excitation above a predetermined MVA characteristic, thus preventing the machine from reaching underexcited conditions which would endanger its synchronizing with the power system.
What is a Remedial Action Scheme? What is its purpose?
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 SPS does not include:
- -underfrequency or undervoltage load shedding, or
- -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.
What is the most typical RAS scheme? What is its purpose?
The most typical type of RAS is Gen Shed. Gen shed means 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. Generation shedding 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 the responsibility of the Transmission Coordinator and is typically done automatically through the Energy Management System Advanced Application, TSA-PM.
Units armed for generation shedding are not indicated on the Energy Management System – SCADA One-line diagrams. The contingency which they have been armed for are identified with a flashing “c” on the Areva associated screen.
What alarms may be received on a Gen Shed operation? What is your response to units tripping from Gen Shed operations?
- Some stations are equipped with generation shedding alarms that will notify the Plant Operator of the fact a generation shed operation has occurred. Unfortunately these do not current reside at all plants and are not consistent in their naming convention.
- The generation shed alarm will typically come in as 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 #
When a unit trips the Plant Operator should be able to discern if the unit tripped because of a gen shed operation. If so, the Plant Operator should be prepared to start units and resynchronize at the direction of the Generation or Transmission Coordinator.
In extreme cases, restarting of the generating unit may not be possible if the unit went to a lockout shutdown as a result of the gen shed operation.
What Operating Order documents Station Alarms policy?
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 subsequently telemetered to the BC Hydro Control Centres where they are processed by the EMS, alarming through the Alarm application.
- Analog alarms are generated solely within the BC Hydro Control Centre EMS, alarming 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?
The priority of generating station alarms are determined by BC Hydro Generation Line of Business (GLoB) unless a generating alarm has an impact on transmission system reliability, RTO will accept and approve alarm priority provided by GLoB.
What are the priorities and appropriate response for all generating station alarms?
- Priority 1 Auto operation 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.
When a group of alarms come in at the same time, the alarm of the highest priority should be the focus of attention. Only one of the alarms of a group associated with an incident needs to be entered into CROW.
1T-38 – “Multiple alarms from one substation and/or from one piece of equipment should be reported using single alarm event. There is no requirement to report them individually.”
What is the primary difference in callout procedures for emergency situations versus non-emergency conditions at BC Hydro generating stations?
In an emergency situation where it is necessary to preserve public health and safety, preserve the reliability of the transmission system, limit or prevent damage to property or the environment or to expedite restoration of service, the BCH operator will first call crews by following the callout list (COPS) and call the standby manager at the first opportunity.
In a non-emergency condition, the standby managers shall be contacted first.
What can single generating unit trips be caused by? What is the Plant Operators response?
- Single unit trips are typically due to generator protection operations or generation shedding.
- In this type of scenario, the Plant Operator has four key responsibilities:
- -Respond to any water flow issues while adhering to ramp rates and minimum flows.
- -Aid the Generation Coordinator in replacing the generation, if required.
- -Aid the Transmission Coordinator and any Grid Operators in any corresponding voltage issues.
- -Investigate the cause of the outage, report the forced outage to PSOSE and the BC Hydro Plant Manager (Standby Mgr after hours) and log in CROW.
- If the unit outage was caused by a generation shedding operation, the Plant Operator should re-synchronize the unit (if available) but not load it until directed by the Transmission or Generation Coordinator.
If the unit outage was caused by a protection operation, the outage should be discussed with the BC Hydro Plant Manager (Standby Mgr 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 unit trips are typically due to generation shedding or protections at the station other than the individual generator protection.
- Similar to single unit trips, the Plant Operator should be readily available to support the Generation Coordinator, Transmission Coordinator or Grid Operator to ensure the reliability of the bulk electric system. This is very essential in multiple unit trip situations because typically the disturbance on the system is much larger than losing a single unit and the Plant Operator can provide much assistance in responding to the disturbance.
Again, if it can be discerned that the unit trips were results of generation shedding operations, the Plant Operator should re-synchronize the shed units (if available) but not load them until directed by the Transmission or Generation Coordinator.
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.
- Islanding events occur whenever transmission connecting two generation sources trips as long as there is load in each area. The result of the transmission path tripping is that the two generation sources continue to supply their own area load; however they are no longer synchronously tied to each other. Within cycles will become out of synch with each other as they immediately operate at different frequencies based on governor response.
Transmission Coordinators, Generation Coordinators and Grid Operators are made aware of islanding events through alarms. In the case of islanding events, they should make the Plant Operator aware that no generation changes should be made without their approval (no unilateral action). This includes changes to generation for water control reasons.
What is blackstart? When may a Plant Operator be asked to blackstart a generating station? What is the typical blackstart procedure?
- Blackstart is defined as 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.
- As such, blackstart of generating stations may be performed by the Plant Operator as directed by the Transmission Coordinator, Generation Coordinator or Grid Operator.
- Typical blackstart operations include:
- -Obtain a source of station service (typically local diesel generation)
- -Put an auto-start on the unit(s)
- -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?
- An Environmental Incident is one that has caused, or has the potential to cause, one or more of the following:
- Adverse impact on the quality of air, land or water, wildlife, aquatic species or species at risk;
- Excess 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 statutes 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?
PSOSE and the System Control Manager must be notified immediately of any and all environmental violations relating to water conveyance.
What is a Water Conveyance instruction? Who typically initiates all Water Conveyance instructions?
PSOSE is responsible for instructing the operation of all Non-Power Release Facilities (NPRFs), also known as Water Conveyance instructions.
Where are all Water Conveyance instructions recorded?
Commercial Management (CM) is the principal system for processing instructions for the release of water for non-power purposes and recording all water conveyance operations of NPRFs.
Who maintains Operating Responsibility of SEV generating stations NPRFs? Why?
Typically, Operating Responsibility of all NPRF that can be operated remotely from BC Hydro Control Centres will be maintained by the Control Centre. Operating Responsibility of all local only NPRFs is maintained by Generation. Because SEV can be operated remotely, Operating Responsibility is held by BCH T&D as per OO 1J-11.
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?
The Water Conveyance Implementation Creation screen allows the Operator to record details of NPRF operations that were not initiated by instructions from PSOSE. Possible situations where this arises are flood routing, dam safety related operation, maintaining a steady forebay (e.g. SEV or COM) or managing discharges for downstream tidal influences.
What is the purpose of the paper based log?
To keep records of operations and captured information that may not be already covered by normal electronic logs.
What types of details are recorded in the paper based log?
- PIC and Apprentice on duty
- O/R Assigned to or Returned by station personnel
- General Events not captured by Electronic Logs
- Shift change notes for tasks crossing shifts
- Entries/Exits and Manchecks
- Critical water levels and callout info
What are the operators and apprentices responsibilities associated with the paper based log?
Signing of log to accept shift duties as well as accurate recording and updating of the log are the responsibilities of the Operators and Apprentices.
What does SCADA stand for? Explain SCADA.
The primary purpose of Supervisory Control And Data Acquisition (SCADA) is to monitor, control and alarm plant or regional electric systems from a central location. BC Hydro utilizes this type of system at substations and generating plants to provide supervisory control of switchyard equipment, generators and spillway facilities from FVO/SIO. It also provides telemetry (kV, Amps, MW, MVar and MVA) from those same facilities back to the Control Centres. When equipment changes status or violates a limit, alarms are sent from the substation back to the Control Centre to make operators aware of the condition.
What are the four key functions of SCADA? Define each.
- Telemetry - is the communication of data over a communication channel, in this case from Remote Terminal Units (RTU) at the station to the Control Centre.
- Status Reporting - is the reporting of the change of status of a device at a remote facility. Status of supervisory control points is communicated via communication channels to the Control Centre 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 communicated via communication channels to the Control Centre via the RTU.
- Remote Control - Supervisory control is also referred to as remote control. Supervisory control allows the operation of devices at remote facilities.
What are the three major components of a SCADA system? Define each.
- Master Station
- The master station consists of a computer with the input/output equipment needed to transmit control measures to the remote units and to receive information from them.
- All operator initiated operations (remote) of a RTU are made through the master unit and are reported back to the master from the RTUs. This report back works whether the command was successful or not. If it was successful, the RTU will report back the status change.
- Remote Terminal Units
- RTUs are located at selected stations, and are either wired to perform certain pre-determined functions or are microprocessor based with both memory and logic capabilities.
- On a command from the master unit, the RTU will send commands to the appropriate device to make the requested status change. If the control is successful, the RTU will report back the status change.
- Transducers in the RTU convert quantities such as voltage and current to DC or voltage proportional values for communication to the Control Centres.
- Signals between the Master Station and the RTUs are sent across communication facilities for supervisory control, telemetry and alarm reporting. The communication means is typically microwave; however other systems are also used such as Power Line Carrier.
- Microwave signals utilize microwave towers and repeater stations and are redundantly reliable so are the preferred communication means.
Power Line Carrier uses the transmission lines between two stations as the communication path. Equipment is installed at both ends of the line to put a medium range frequency signal on one phase of the line that does not interfere with the transfer of power between the two stations. This is less reliable due to the fact if the phase were to become grounded, all communications would be lost.
What is the purpose of CM? Who is the owner?
- BCH Generation LOB’s Commercial Management (CM) System stores data and provides processes for managing generation capabilities, dispatchable generators and planned maintenance outages, for use by key users.
- It provides information for those who are managing, maintaining and operating power plants.
CM also provides a clear record of water conveyance via non-power release facilities (NPRFs). This gives credibility and integrity to BC Hydro’s data and protects BC Hydro’s interests in the event of challenges to the operation of BCH plants.
What is the Plant Operators responsibility with respect to CM?
BC Hydro Plant Operators are responsible for the operation of CM per the details in OO 1T-53.
“The individual who has operational control of the generating unit in real time, including alarm monitoring responsibility. This individual also has the responsibility to conduct a risk assessment of any action requested by others regarding the operation of generation or water conveyance facilities. In some cases the operator is in a generating facility control room (e.g., GMS, BGS) and in other cases the operator is in a BCTC Real-time Operations Control Center (LMC, SIC, VIC, NCC, FVO or SIO). In the CROW system, the Operator will make REAL TIME DECLARATIONS about certain unit restrictions as outlined in Section 3.0 and will UPDATE STATUSES ON OUTAGES to ACTIVE, COMPLETED or RETURNED on maintenance outage detail screens to keep the outage records current. They will also DECLARE FORCED OUTAGES AND DERATINGS as required when equipment does not operate as intended. The Generation Operator also has Operating Responsibility for water conveyance operation and will implement water conveyance instructions directly or call on Power Facilities where required. They will also record in CM all operations of non-power release facilities including spillway gates, syphons, valves, etc.”
What is the purpose of DCM? Who is the owner?
Grid Operations’ Dispatch and Compliance Monitoring (DCM) System is a real-time communication, workflow processing and data management application which was created to enhance the ability of Grid Operations to electronically interact with all transmission market participants in a consistent, transparent, non-discriminatory, and auditable manner.
It resides within Grid Operations and has security measures built in to protect confidential information. This system was created in support of the need to have a Grid Operations application which would handle and archive increasing volumes of business with increasing numbers of market participants who require independence from the BC Hydro generation database.
What is the Plant Operators responsibility with respect to DCM?
BC Hydro Plant Operators are responsible for the operation of DCM per the details in OO 1T-56.
“For BC Hydro, the Generation Operator is either an OAD who has direct control of a generator, or a plant Operator or SSCO in a generating facility who has direct control of a generator, or a field tradesperson who has direct control of a generator. The individual who operates a generator 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.”