HSI Quiz Bank Flashcards

Question

Which of the following is a potential source of Contingency Reserve? 1. Offline generation that takes 10 minutes to start and ramp to full output 2. Online generation at full load 3. Controllable load resources 4. Voltage reductions 2 and 3 1 and 2 1 and 3 3 and 4

Answer 1

1 and 3 Feedback: Each Balancing Authority shall have access to and/or operate Contingency Reserve to respond to Disturbances. Contingency Reserve may be supplied from generation, controllable load resources, or coordinated adjustments to Interchange Schedules. NERC Standard BAL 002

Answer 2

One minute or less Feedback: Simultaneous contingencies - multiple contingencies occurring within one minute or less of each other shall be treated as a single contingency. If the combined magnitude of the multiple contingencies exceeds the most severe single contingency, the loss shall be reported, but excluded from compliance evaluation. NERC Standard BAL-002

Answer 3

False Feedback: Each Reserve Sharing Group shall comply with the DCS. A Reserve Sharing Group shall be considered in a Reportable Disturbance condition whenever a group member has experienced a Reportable Disturbance and calls for the activation of Contingency Reserves from one or more other group members. (If a group member has experienced a Reportable Disturbance but does not call for reserve activation from other members of the Reserve Sharing Group, then that member shall report as a single Balancing Authority.) NERC Standard BAL 002

Answer 4

-55 MW ACE in 15 minutes Feedback: A Balancing Authority shall return its ACE to zero if its ACE just prior to the Reportable Disturbance was positive or equal to zero. For negative initial ACE values just prior to the Disturbance, the Balancing Authority shall return ACE to its pre-Disturbance value within 15 minutes. NERC Standard BAL 002

Answer 5

The loss of a 950 MW generating unit at 100% output Feedback: BAL-002 states "A Balancing Authority or Reserve Sharing Group shall calculate and report compliance with the Disturbance Control Standard for all Disturbances greater than or equal to 80% of the magnitude of the Balancing Authority's or of the Reserve Sharing Group's most severe single contingency loss." The 950 MW unit is 95% of the most severe single contingency and meets the criterion of "greater than or equal to 80%..." NERC Standard BAL 002

Answer 6

600 MW Feedback: A Balancing Authority is required to maintain enough contingency reserve to cover its Most Severe Single Contingency (MSSC). In this example 600 MW.

Answer 7

100% for all reportable disturbances Feedback: A Balancing Authority or Reserve Sharing Group shall meet the Disturbance Recovery Criterion within the Disturbance Recovery Period for 100% of reportable disturbances. NERC Standard BAL 002

Answer 8

ACE Feedback: The change in demand-supply balance following a sudden loss of load or generation failure, results in a sudden change in the Balancing Authority's ACE, which means the Balancing Authority or Reserve Sharing Group is off schedule and dragging or pushing the tie lines. If the Balancing Authority lost load, then they would have too much generation causing the Interchange Actual to exceed the Interchange Schedule of the ACE equation. Power flow off the Balancing Authority's tie line in excess of the Interchange Schedule. Losing generation would cause the Balancing Authority to have more load then generation, causing the Interchange Actual to have power flowing into the Balancing Authority of the Interchange Schedule. Performance Standards Reference Document Section 2 NERC Reliability Standard BAL-001 NERC Reliability Standard BAL-002

Answer 9

Contingency reserve Feedback: DCS, or the Disturbance Control Standard, measures a Balancing Authority's ability to respond to system disturbances and measure whether the Balancing Authority's contingency reserve is adequate. If the calculated percent recovery from disturbances is less than 100%, the Balancing Authority or Reserve Sharing group must increase its contingency reserve requirement by the contingency reserve adjustment factor. NERC Standard BAL 002

Answer 10

60 MWs Feedback: Since the frequency dropped .05 Hz, and the Frequency Bias Setting of the Balancing Authority is 120 MW/.1 Hz, assuming the Frequency Response Characteristic of the Balancing Authority is very close to the Bias Setting (B), you would expect the Balancing Authority to respond with half of its Bias setting (.05 Hz is half of .1 Hz so half of the 120 MWs).

Answer 11

120 MW Feedback: Frequency Bias (which is always a negative number) is measured in MW per tenth Hz (MW/0.1 Hz). This means that if scheduled and actual frequency are at 60.000 Hz and the frequency drops to 59.900 Hz, a Balancing Authority with a 200 MW/0.1 Hz Frequency Bias would contribute 200 MW to help arrest the frequency decline. The frequency bias obligation portion of the ACE equation is -10 * B * (FA - FS) Plugging in actual numbers gives us -10 * 200 MW/0.1 Hz * (59.94 Hz - 60 Hz) = -2000 Mw/Hz * -0.060 Hz - 120 MW Your Balancing Authority would over generate by 120 MW. This should happen naturally with the response of your generator governors and loads to the declining frequency. A shortcut to this calculation is figuring that 0.06 Hz is 60% of 0.1 Hz and 60% of 200 MW is 120 MW.

Answer 12

Governor control systems Feedback: NERC Standard BAL 003 states, "Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is as close as practical to, or greater than, the Balancing Authority's Frequency Response." Further, the Glossary of Terms used in the Reliability Standards defines frequency response as "The sum of the change in demand, plus the change in generation, divided by the change in frequency, expressed in MW per 0.1 Hertz (MW/0.1 Hz). The loss of generation on an Interconnection results in a corresponding decrease in frequency. The first control systems to respond to a frequency disturbance are the generator governor control systems. Declining frequency causes the governor controls to open valves to increase input to the prime mover, increasing the torque angle and MW output of the generator. NERC Standard BAL-003

Answer 13

The Balancing Authority's Frequency Bias Setting shall be modified to reflect the combined Frequency Bias Setting of both Balancing Areas. Feedback: BAL-003 requires each Balancing Authority performing Overlap Regulation Service to modify its Frequency Bias Setting to represent the Frequency Bias Setting for the combined Balancing Authority Area. This combined setting should be equivalent to either the sum of the Balancing Area's Frequency Bias Settings, or the single Frequency Bias Setting for the combined area as determined through the yearly NERC process for assigning and implementing Frequency Bias Settings

Answer 14

Equal to or more negative than the Frequency Response Obligation (FRO) Feedback: BAL-003 requires the annual FRM for a Balancing Authority or FRSG be equal to or more negative than its FRO.

Answer 15

ACE will be a positive value and AGC will lower generation. Feedback: If a Balancing Authority establishes a frequency bias setting less than its frequency response characteristic, the Balancing Authority ACE value will become positive if frequency falls below 60 Hz due to events outside the balancing area. In response to the positive ACE value, the AGC will reduce the output of generators under its control. This is not the appropriate response to a reduction in Interconnection frequency caused by a loss of generation in an external balancing area, since pulsing the units of the Balancing Authority LOWER in response to a LOSS of generation and only aggravate the frequency decline. This example highlights the importance of setting the Frequency Bias Setting equal to, or greater than, the Balancing Authority's Frequency Response.

Answer 16

ACE will be a negative value and AGC will increase generation. Feedback: If a Balancing Authority establishes a frequency bias setting less than its frequency response, when the frequency drops its ACE becomes positive. In response to the positive AGC value, the AGC reduces the output of generators under its control. This response is not appropriate to a reduction in frequency caused by a loss of generation in an external balancing area. Therefore, it will take longer to restore frequency back to schedule on the Interconnection. In this example, the Balancing Authority's Frequency Bias Setting is set higher than its Frequency response characteristic (which is allowable) and results in ACE being negative after the external disturbance and the Balancing Authority's generation on AGC picks up and provides more support to the Interconnection than just its natural frequency response. the result, it will take longer to restore frequency back to schedule on the Interconnection.

Answer 17

Overlap regulation service

Answer 18

The Balancing Authority's percentage of the Interconnection's generation and load. Feedback: BAL 003 requires that a Balancing Authority meets its obligation to respond to frequency deviations caused by disturbances in the Interconnection. This obligation is called Frequency Response Obligation (FRO) and is calculated each year based on a Balancing Authority's percentage of the annual generation and load in the Interconnection to which it belongs.

Answer 19

Adding individual FRO of each member Feedback: NERC allows Balancing Authorities to form Frequency Response Sharing Groups (FRSGs) with other Balancing Authorities to jointly meet their FROs. These FRGs determine their joint FRO by adding up the member's individual FROs

Answer 20

All answers are correct Feedback: EPRI Power System Tutorial

Answer 21

Increase MW output Feedback: Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is close as practical to, or greater than, the Balancing Authority's Frequency Response. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless such operation is adverse to system or Interconnection reliability. It can be determined that because Net Interchange deviation is negative, and because frequency is less than 60 Hz, Balancing Authority A's AGC will be pulsing its generators to increase generator output. This could be in response to circumstances such as a disturbance within the Balancing Area of poor control and the resulting negative ACE value. Any time Interchange Actual is less that Interchange Schedule the remainder is a negative number, and the Interconnection frequency is below scheduled frequency which means that the frequency bias portion of the ACE equation contributes to an even more negative ACE. When ACE is negative Automatic Generation Control (AGC) will be pulsing the Generator governors to increase megawatt output. NERC Standard BAL-003

Answer 22

It prevents governors from operating when slight variations occur in the system's frequency. Feedback: The governor dead band prevents governors from operating when slight variations occur in the system's frequency which would result in unnecessary equipment wear, such as control valves and linkages.

Answer 23

310 MWs Feedback: A 5% droop means the generator will respond with its full capacity range for a 5% change in frequency (.05 x 60 Hz = 3 Hz). In this example, the frequency dropped by .06 Hz, so we use the following ratio: (500 MW/3 Hz) = (? MW/.06 Hz). If we cross multiply we get 3(?) = .06(500 MW) and solving for? we get 10 MW of change on the unit. Since we know frequency dropped, the unit responded by increasing generation by 10 MWs resulting in output of 310 MWs.

Answer 24

2.4 Hz Feedback: A 4% droop setting means that for a 4% change in frequency, the unit will respond with 100% of its capacity. 4% of 60 Hz is 2.4%.

Answer 25

The amount of frequency change that occurs before the governor starts to respond. Feedback: Generators respond to frequency deviation inversely or opposite of the frequency deviation. If frequency is low, a generator responds in proportion to their size by increasing output and vice versa. The governor dead band is in place to ensure generators are not continuously responding or chasing frequency.

Answer 26

Net Actual Interchange greater than Scheduled Interchange. Feedback: When a loss of generation occurs, Interconnection frequency decreases. Turbine governor respond to a frequency deviation and increase the output of their generators in proportion to their size and the amount of frequency deviation. The frequency bias portion of the ACE equation allows the generators in your Balancing Area to increase MW output without AGC trying to lower them at the same time. The result is a positive Net Actual Interchange deviation for your Balancing Authority. If ACE is zero while Interchange actual is greater than Interchange schedule during this disturbance your Balancing Authority's frequency bias is equal to your frequency response.

Answer 27

Automatic Generation Control Feedback: The Balancing Authority's AGC shall compare total Net Actual Interchange to total Net Scheduled Interchange plus Frequency Bias obligation to determine the Balancing Authority's ACE. Single Balancing Authorities operating asynchronously may employ alternative ACE calculations such as (but not limited to) flat Frequency Control. If a Balancing Authority is unable to calculate ACE for more than 30 minutes, it shall notify its Reliability Coordinator. Governor action is not intended to keep the system at 60 Hz. Governors arrest frequency deviations, but AGC maintains system frequency to a schedule by pulsing the generator governors to either increase or decrease MW production depending on the need. When AGC pulses the generator governor to increase megawatts on a fossil steam generator, it causes the steam regulating valves to open more, allowing more steam across the generator turbine blades. This action should increase the mechanical energy on the turbine which is then converted to electrical energy. NERC Standard BAL-005

Answer 28

Both answers are correct Feedback: Automatic Generation Control uses the ACE equation to minimize the Inadvertent Interchange among Balancing Authority areas and provide frequency support for the Interconnection.

Answer 29

Suspend AGC and investigate Feedback: "The Balancing Authority shall operate AGC continuously unless such operation adversely impacts the reliability of the Interconnection. If AGC has become inoperative, the Balancing Authority shall use manual control to adjust generation to maintain the Net Scheduled Interchange." In the scenario given, the AGC clearly is inoperative and since the frequency has dramatically declined to 59.80 Hz, is adversely impacting the reliability of the Interconnection. The negative ACE value is not unexpected; however, AGC should be pulsing units up instead of down. Therefore, suspending AGC and going to manual control to adjust generation is the recommended course of action.

Answer 30

Economically Feedback: Automatic Generation Control automatically, with an economic component, adjusts a Balancing Authority's generation in response to change in its ACE.

Answer 31

Scheduled Net Interchange component, NIS Feedback: Dynamic schedules are reflected in the NIS, or Scheduled Interchange component of the ACE equation.

Answer 32

Actual Net Interchange component, NIA Feedback: Pseudo-ties are reflected in NIA, or Actual Interchange component of the ACE equation.

Answer 33

Flat Frequency Control Feedback: The Balancing Authority's AGC shall compare total Net Actual Interchange to total Net Scheduled Interchange plus Frequency Bias obligation to determine the Balancing Authority's ACE. Single Balancing Authorities operating asynchronously may employ alternate ACE calculations such as (but not limited to) flat frequency control. If a Balancing Authority is unable to calculate ACE for more than 30 minutes it shall notify its Reliability Coordinator. Normally, the Tie Line Bias control mode, which compares the Net Actual Interchange to the Net Scheduled Interchange plus the Balancing Authority's frequency bias obligation, should be used. However, if a Balancing Authority is operating asynchronously, or separated from the Interconnection, it should switch to Flat Frequency Control. Because its tie lines are no longer connected to the Interconnection and it is more important for the Balancing Authority to maintain 60 Hz. In the Flat Frequency control mode, ACE is looking only at the system frequency, not the Interchange portion of the ACE equation. Alternatively, the separated Balancing Authority could choose to continue operating in Tie Line Bias Control mode but with all Interchange schedules set to zero. This decision is equivalent to operating in Flat Frequency mode.

Answer 34

Flat Tie Line Control Feedback: If the Balancing Authority is unable to switch to a reliable frequency indication, Flat Tie Line control mode should be used for AGC. The Balancing Authority should immediately initiate maintenance activity to repair the frequency indication so AGC can be returned to Tie-Line Bias mode as soon as possible.

Answer 35

Manual Control Feedback: The NERC Standard states, "The Balancing Authority shall operate AGC continuously unless such operation adversely impacts the reliability of the Interconnection. If AGC has become inoperative, the Balancing Authority shall use manual control to adjust generation to maintain the Net Scheduled Interchange? NERC Standard BAL 005

Answer 36

0.001 Hz Feedback: BAL-005, R3: Each Balancing Authority shall use frequency metering equipment for the calculation of Reporting ACE: 3.1 that is available a minimum of 99.95% for each calendar year; and 3.2 with a minimum accuracy of 0.001 Hz.

Answer 37

99.95% Feedback: BAL-005, R3: Each Balancing Authority shall use frequency metering equipment for the calculation of Reporting ACE: 3.1 that is available a minimum of 99.95% for each calendar year; and 3.2 with a minimum accuracy of 0.001 Hz.

Answer 38

99.5% Feedback: BAL-005, R5: Each Balancing Authority’s system used to calculate Reporting ACE shall be available a minimum of 99.5% of each calendar year.

Answer 39

14:00 Feedback: BAL-005, R2: A Balancing Authority that is unable to calculate Reporting ACE for more than 30 consecutive minutes shall notify its Reliability Coordinator within 45 minutes of the beginning of the inability to calculate Reporting ACE.

Answer 40

An Operating Process for identifying and mitigating errors Feedback: BAL-005, R6: Each Balancing Authority that is within a multiple Balancing Authority Interconnection shall implement an Operating Process to identify and mitigate errors affecting the accuracy of scan rate data used in the calculation of Reporting ACE for each Balancing Authority Area.

Answer 41

Use the IME portion of the equation to adjust for the meter error

Answer 42

All are required to be within the metered boundaries of a Balancing Authority. Load Feedback: All generation, transmission, and load operating within an Interconnection must be included within the metered boundaries of a Balancing Authority Area. NERC Standard BAL-005

Answer 43

Overlap regulation service Feedback: Overlap regulation service is a method of providing regulation service in which the Balancing Authority providing the regulation service, incorporates all other Balancing Authority's tie lines, frequency response, and schedules into its own AGC/ACE equation.

Answer 44

Use the Meter Error part of the ACE equation and remain in Tie-Line Bias mode Feedback: In this case meter error is not the issue, but with the meter out of service, the flow on that tie-line is not being included in the Actual Net Interchange portion of the ACE equation. The tie line flow can be determined by calling the adjacent BA periodically to get updates, or by using State Estimator and the value can be entered by the operator in the Meter Error term of ACE. It is better to operate in tie-line bias if at all possible and manually update the tie line information.

Answer 45

B Feedback: NIA is affected due to generators responding to frequency through governor response anytime frequency is outside the governor dead band.

Answer 46

6 seconds Feedback: BAL-005, R1: The Balancing Authority shall use a design scan rate of no more than six seconds in acquiring data necessary to calculate Reporting ACE.

Answer 47

True Feedback: While Interchange Transactions can be between any two Balancing Authorities, Interchange Schedules are only between adjacent Balancing Authorities. The exception to this is if two non-adjacent Balancing Authorities have a Dynamic Schedule representing jointly owned generation or load.

Answer 48

Generator Ramping Capability Energy Magnitude

Answer 49

When the ramp starts

Answer 50

Sink Balancing Authority must confirm the transaction status is Confirmed.

Answer 51

The amount of transfer capability in the transmission network remaining for further commercial activity over and above already committed uses

Answer 52

The Reliability Coordinator may need to modify or curtail Interchange Transactions impacting the overloaded facility Feedback: Since the overload is due to excessive interchange power flows, re-dispatching generation internally may not help the overloaded facility. The Interchange Transactions affecting the SOL must be reduced and will be initiated by the Reliability Coordinator.

Answer 53

Balancing Authority Feedback: Balancing Authorities and Transmission Service Providers are responsible for evaluating and approving interchange transactions. Reliability Coordinators do not approve transactions, but are aware of all transactions affecting their reliability area. They will curtail transactions when necessary for reliability issues. Transmission Operators are not involved in the tagging process at all.

Answer 54

Determine the capability of supporting the magnitude of the Interchange

Answer 55

Source Balancing Authority and Sink Balancing Authority

Answer 56

Confirmed status

Answer 57

A computer software program of Electronic Tagging

Answer 58

Sink Balancing Authority must ensure the transaction status is Confirmed.

Answer 59

False Feedback: Power flow follows paths of least impedance. Usually, the largest percentage of the total transaction will flow on the scheduled path. But most transactions will result in unscheduled flow on other paths, sometimes causing congestion. The amount of flow on a path resulting from a transaction is called the Power Transfer Distribution Factor, or PTDF.

Answer 60

All involved Balancing Authorities, Transmission Service Providers, Purchasing Selling Entities, and affected Reliability Coordinators

Answer 61

The state where no party has denied, and all required parties have approved the Arranged Interchange Feedback: Confirmed Interchange - The state where no party has denied, and all required parties have approved the Arranged Interchange.

Answer 62

The energy profile (including non-default ramp) throughout a given time period, based on the aggregate of all Confirmed Interchange occurring in that time period

Answer 63

To ensure Balancing Authorities implement the Interchange as agreed upon in the Interchange confirmation process. Feedback: "Purpose: To ensure that Balancing Authorities implement the Interchange as agreed upon in the Interchange confirmation process."

Answer 64

Identical in magnitude Opposite in sign

Answer 65

Adjacent Balancing Authorities BA-A and BA- C

Answer 66

In the Actual Net Interchange term of their respective ACE equations

Answer 67

Direct the scheduling or modification of Confirmed or Implemented Interchange.

Answer 68

Dynamic Schedule in NIs for each Balancing Authority

Answer 69

Implement the transaction into the involved Balancing Authorities' ACE equation Coordinate with the Transmission Operator if an HVDC is involved in path

Answer 70

Current transformers

Answer 71

All of the above Feedback: The synchronizing relay protects the open circuit breaker from closing when two areas of the power system have large differing values. For example, if the line was closed into a substation bus that had different phase angles or huge voltage differences, large amounts of current and reactive power would flow from one part of the system to another. This can cause high voltage swings, bumping or shaking and possibly knock generators off line and damage equipment.

Answer 72

Ground fault Feedback: The most common fault on the transmission system is the line to ground fault. This means that the current on the transmission line has found a path to ground, causing a short circuit on the system. That means that the current on the transmission line has found a path to ground, causing a short circuit on the system. There are many causes of ground faults; blown insulators, animals around the equipment, lightning, and vegetation such as trees and even smoke from a forest fire.

Answer 73

System voltage decreases due to the fault. Feedback: The arc was initiated due to the current flow through the disconnect as the disconnect arm separated from the receiver. If the fault is not interrupted quickly, the high current flow will cause the system voltage to dip to dangerously low levels. These resulting low voltages will cause motors to draw more current, lights to dim, and if there are not enough reactive reserves available to stabilize voltage, a blackout could occur.

Answer 74

minimize damage and isolate problems on the system. Feedback: Protective Relays are designed to detect a fault and isolate the equipment by opening or tripping a device such as a circuit breaker. Basically, minimizing damage and isolating problems.

Answer 75

Timed Overcurrent relay Feedback: High voltage transformers are normally protected by differential relays for problems occurring to the transformer itself. However, a differential relay would not operate as the result of high current flow passing through the transformer feeding a fault on the distribution system. To protect the transformer from high fault current, overcurrent relays are installed to take the transformer off line should a lingering high current fault occur as the result of a distribution circuit breaker not opening when it should.

Answer 76

three Feedback: Distance relay schemes usually use three zones of protection. Zone 1 usually covers 80 to 90% of the line section and trips instantaneously at high speed. Zone 2 covers the entire length of the line, plus 20 to 50% into the other lines feeding off the same bus. Zone 2 will have a time delay of about 25 cycles and basically serves as a backup to zone 1. Zone 3 covers the entire length of the protected line, plus a 50% into the lines feeding off the same bus. Zone 3 has an even longer trip delay of anywhere from 60 cycles to 90 cycles depending on the company. protective relay strategy. It primarily serves as a backup to Zone 1 and Zone 2.

Answer 77

There is a fault on the bus, and the bus differential scheme will operate Feedback: When the current leaving the bus differential scheme is not equivalent to the current entering it, a fault condition exists. This also means that the bus differential scheme will operate to open the circuit breaker. This means the answer that indicates 1.) there IS a fault on the bus and 2.) the buss differential scheme WILL operate, is the correct answer.

Answer 78

Differential Relay Feedback: Relay 87 is a differential relay per IEEE Relay Standards naming convention. An entire bus cleared instantaneous is typically the result of a differential of current into and out of the bus.

Answer 79

All of the above Feedback: Because there is more power leaving the transformer differential scheme than entering it, we can conclude there is a fault on the transformer. When a fault occurs, it produces a secondary current that operates the differential relay, which in turn opens the circuit breakers. This means the answer indicating "all of the above" is correct.

Answer 80

misoperation Feedback: Relays are installed throughout the power grid in overlapping zones of protection to detect faults. When a fault occurs, isolation of the fault should affect the smallest amount of the power grid as possible. Therefore, each relay that detects a fault cannot and should not be the primary tripping source or huge portions of the power grid would be interrupted for a single fault. To prevent this from happening, delays are designed into relays (most of the time they are timers) allowing a relay outside the primary tripping zone to operate quickly but only if the primary relay misoperates. If the relays do not operate as designed, a misoperation has occurred.

Answer 81

A relay is designed to operate a circuit breaker for a fault in 3 cycles, but did not respond at all, causing the backup overcurrent relay to operate in 25 cycles. Feedback: A protection system misoperation is caused when protective relays do not respond to system conditions as designed. A relay misoperation causing a fault to stay on the system longer that it should, or de-energizing a line when it should not, are examples of protective system misoperations. Protection system misoperations must be evaluated to determine why they occurred and what can be done to ensure that they will not occur again.

Answer 82

21 Distance or 67 Directional Overcurrent Feedback: Transmission lines are usually protected by distance relays and ground overcurrent relays. Whether the relays are electromechanical, solid state, or computer type relays does not matter when it comes to the numbering for the distance relays. That number will usually be a 21 as defined by IEEE. Ground relay s, however, may be designed by different numbers. For example, if the ground relay is an older electromechanical directional ground relay, it will be a 64. If the relay is the newer computerized directional ground relay, it will be a 67. Whatever the case, transmission lines are usually protected by 21 distance and 64 or 67 directional ground or directional overcurrent relays.

Answer 83

Distance Relay (Device 21) Feedback: A distance relay (Device 21) uses a combination of current transformer (CT) measurements and potential transformer (PT) measurements and operates when the ratio of the PT measurements to CT measurements is below a certain limit for a given period of time.

Answer 84

The voltage decreased and current increased. Feedback: When a fault occurs on the power grid, the voltage decreases and the current increases resulting in a decrease in the impedance in the vicinity of the fault. the change in voltage and current is the input causing the distance relay to respond.

Answer 85

True Feedback: Relays can detect faults that occur in other line sections. due to the overlapping zones of protection. To prevent relays from operating out of sequence or too rapidly, communication signals are transmitted from one relay to another controlling how the relays will respond.

Answer 86

False Feedback: Transfer trip signals are a form of pilot relaying. Pilot relay signals can be sent over various types of communication channels. Examples of communication channels are pilot wires, power-line carrier, satellite, fiber optics, microwave, and even telephone lines.

Answer 87

Transmission Operator and Host Balancing Authority Feedback: Each Generator Operator shall coordinate all new protective systems and all protective system changes with its Transmission Operator and Host Balancing Authority.

Answer 88

Affected Transmission Operators and Balancing Authorities Feedback: Each Transmission Operator and Balancing Authority shall monitor the status of each Special Protection System in their area and shall notify affected Transmission Operators and Balancing Authorities of each change in status.

Answer 89

A 161/69/13 kV transformer was de-energized due to a transformer differential relay operation at exactly the same time that a 161 kV line ground fault occurred on one of the 161 kV lines that feed from the station's 161 kV bus. Feedback: A line fault should not affect the transformer differential relay. If a ground fault occurred on one of the 161KV lines that feed out of the station a couple of things could have happened to cause the transformer differential relay to operate at the same time. Saturated CT's or Zero sequence current could have gotten into the current transformers unbalancing the transformer differential relay. Either one of these would require a misoperation analysis and a corrective action plan to be submitted to the RRO.

Answer 90

Its Transmission Operator and others that may require changes in their protection system Feedback: Each Generator Operator shall notify the affected Transmission Operators in advance of changes in generation or operating conditions that could require changes in the Transmission Operator's protection systems.

Answer 91

Re-dispatch generation, request MVAR support from each generator, place all available voltage support equipment on line, and curtail load if necessary. Feedback: The increased flow on the 230kV line has pushed it above its Surge Impedance Loading causing the line to become a consumer of reactive power. Coupled with the loss of the voltage support from the 345kV line, this results in a System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) violation. NERC requires the Transmission Operator to resolve the operating limit violation as soon as possible but no longer than 30 minutes. The Transmission Operator's first choice might be re-dispatch generation and request all Generator Operators increase their voltage support. If this works, it should prepare for the next contingency. If the transmission system is still in violation, the next choice would be to curtail load in the area.

Answer 92

Remove from service one of several lightly loaded parallel lines Feedback: A transmission Operator should consider removing lightly loaded lines as long as there are parallel lines. This causes the other lines to increase in load and produce less MVAR, and voltage will drop. A quick study would be performed first to ensure no other reliability issues would arise. Generators are a dynamic resource and should be considered last for adjusting voltage conditions.

Answer 93

Reactors Feedback: Most generators have the capability to absorb reactive power by under-exciting the generator rotor. Static VAR compensators are also able to absorb excessive reactive power using its reactors as needed in just a few cycles. However, generators with their AVR in service and static VAR compensators are dynamic resources and should already be in service. If voltage is spiking due to an unexpected drop in customer load, reactors, which are typically located at high voltage stations, can be brought into service as needed.

Answer 94

Heavy power flow in and across the area. Feedback: Low voltages can almost always be attributed to heavy power flows. Heavy power flows cause lines to consume MVARS due to their inductive properties and without sufficient MVAR resources, voltages drop.

Answer 95

ensure they do not burden adjacent Transmission Operators with excessive reactive power flow across transmission tie lines and operate within System Operating Limits and Interconnection Reliability Operating Limits. Feedback: Operating within System Operating Limits and Interconnection Reliability Operating Limits by Transmission Operators is critical to reliability. Implementing a system voltage schedule and providing a copy of the schedule to its Reliability Coordinator and adjacent Transmission Operators helps ensure excessive reactive power flow does not flow across transmission tie lines.

Answer 96

Surge Impedance Loading Feedback: Transmission Operators monitor the loading or current flow on a transmission line to determine whether the transmission lines are helping maintain system voltage. A transmission line at its Surge Impedance Loading (SIL) level is producing reactive power equal to the reactive power being consumed.

Answer 97

dynamic Feedback: Generators and lightly loaded transmission lines are examples of dynamic reactive resources. These reactive resources are considered dynamic due to their ability to provide or absorb varying amounts of VARs based on the needs of the system. Static VAR Compensators, or SVCs, are also a dynamic reactive resource. The word static in the name refers to the fact that they have no moving parts as compared to generators and synchronous condensers which are rotating machines.

Answer 98

reactive resources Feedback: Based on its assessment of the system, each Transmission Operator shall have evidence of scheduling sufficient reactive resources within its area to protect the voltage levels under normal and contingency conditions. Transmission Operators can provide sufficient reactive resources through various means including, but not limited to, reactive generation scheduling, transmission line and reactive resource switching, and controllable load use.

Answer 99

reduce reactive power flow and losses between the generator and the inductive load Feedback: Since it is difficult to transmit reactive power over long distances, it is better to have reactive power reserves close to the load, where it is most needed.

Answer 100

Ensure that sufficient dynamic and static MVAR sources are available. Feedback: Based on its assessment of the system, each Transmission Operator shall have evidence of scheduling sufficient reactive resources within its area to protect the voltage levels under normal and contingency conditions. Transmission Operators can provide sufficient reactive resources through various means including, but not limited to, reactive generation scheduling, transmission line and reactive resource switching, and using controllable load.

Answer 101

Reactors Feedback: Most generators have the capability to absorb reactive power by under-exciting the generator rotor. Static VAR compensators are also able to absorb excessive reactive power using its reactors as needed in just a few cycles. However, generators with their AVR in service and static VAR compensators are dynamic resources and should already be in service. If voltage is spiking due to an unexpected drop in customer load, reactors, which are typically located at high voltage stations, can be brought into service as needed.

Answer 102

Re-dispatch generation, request MVAR support from each generator, place all available voltage support equipment on line, and curtail load if necessary. Feedback: The increased flow on the 230kV line has pushed it above its Surge Impedance Loading causing the line to become a consumer of reactive power. Coupled with the loss of the voltage support from the 345kV line, this results in a System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) violation. NERC requires the Transmission Operator to resolve the operating limit violation as soon as possible but no longer than 30 minutes. The Transmission Operator's first choice might be re-dispatch generation and request all Generator Operators increase their voltage support. If this works, it should prepare for the next contingency. If the transmission system is still in violation, the next choice would be to curtail load in the area.

Answer 103

Strength of the bus at the closed end. Length of the line being energized. Feedback: Two factors that determine the amount of voltage rise on the line are the length of the line being energized and the strength of the bus at the closed end.

Answer 104

by placing a high voltage transmission line in service or taking one out of service. Feedback: Transmission lines can be a source of reactive power or a sink of reactive power. MVAR production can be increased or decreased by placing a high voltage transmission line in service or taking one out of service. This is an acceptable method of controlling voltage on the transmission system but should only be used when engineering studies indicate taking the line out of service will not have a negative impact on reliability.

Answer 105

A shortage of reactive resources Feedback: The root cause of low voltage is simply not having enough reactive power. If voltage needs to be raised, increase the reactive output of the generators, and place capacitor banks in service. When there is a shortage of reactive power, voltages drop as MW load increases. As current flow increases, making the transmission system more inductive, losses on the system increase.

Answer 106

The voltage rise that occurs when the transmission system has an open-ended, energized transmission line. Feedback: A very important factor in voltage control is placing lines in service after they have been de-energized. In order to place a line in service, one end usually has to be closed while the other end of the line remains open for a period of time. The effect the open ended energized line has on the transmission system is known as the Ferranti Voltage Rise Effect.

Answer 107

When a line is loaded below its SIL, voltage increases, and inductive reactive resources will reduce the voltage. When a line is loaded above its SIL, voltage decreases, and capacitive reactive resources will increase voltage. Feedback: A transmission line loaded above its SIL (Surge Impedance Loading) decrease voltage, while a transmission line loaded below its SIL increases voltage. Capacitive reactive resources, such as capacitor banks, are designed to add MVARs to the system to increase voltage. Inductive reactive resources, such as reactors, are designed to absorb MVARs from the system to decrease voltage.

Answer 108

As close to the heaviest inductive load areas as possible. Feedback: The closer you can place reactive power sources to the inductive load, the less current you will have on the transmission system thus fewer MW and MVAR losses.

Answer 109

Yes Feedback: Generators off-line for testing and during start-up or shutdown modes, cannot operate in AVR mode. Generators that cannot operate with the Automatic Voltage Regulator in service and controlling voltage may be unable to meet their generator voltage or reactive power schedule and the Transmission Operator must be notified.

Answer 110

A target value communicated by the Transmission Operator to the Generator Operator establishes a tolerance band within which the target value is to be maintained during a specified period. Unless exempted by the Transmission Operator, each Generator shall maintain the generator voltage or Reactive Power schedule. When a generator's Automatic Voltage Regulator is out of service, the Generator Operator shall use an alternative method to control the generator reactive power output to meet the schedule provided by the Transmission Operator. Feedback: Voltage control is a critical factor in the reliability of the Interconnection. Generators following a Voltage Schedule help keep system voltage at a satisfactory level. The voltage or Reactive Power schedule is a target value communicated by the Transmission Operator to the Generator Operator and is to be maintained for the specified period unless the Generator Operator is granted an exemption by the Transmission Operator, or the Transmission Operator has instructed the Generator Operator to modify voltage. When a generators Automatic voltage Regulator (AVR) is out of service, the Generator Operator shall use an alternative method to control the generator voltage and reactive output in order to meet the schedule.

Answer 111

Transmission Operator Feedback: It is the responsibility of the Generator Owner to provide this information to the Transmission Operator and Transmission Planner, however, the Transmission Operator makes the request for step-up transformer tap changes as needed to support system voltages.

Answer 112

30 Calendar Days Feedback: The Generator Owner has 30 calendar days to supply the Transmission Operator and Transmission Planner with requested information on its set-up transformers and auxiliary transformers. This information is used by the Transmission Operator and Transmission Planner to calculate the step-change percentage.

Answer 113

Generator Owner Feedback: Ater consulting with the Transmission Operator, the Generation Owner will ensure its step-up transformer taps are modified per the Transmission Operator's documentation, unless such action would violate safety, an equipment rating, a regulatory requirement, or a statutory requirement. If a Generator Owner cannot comply with the specification, it shall notify the Transmission Operator and provide the technical justification.

Answer 114

A Real-time communication or procedure has been provided to the Transmission Operator notifying it the generator is offline and will be in manual voltage control until it's ramped up to its minimum continuously sustainable load. Feedback: The Generator Operator operates each generator interconnected to the BES in the Automatic Voltage Control mode unless the Transmission Operator has specified a different control mode or the Generator Operator has notified the Transmission Operator through a real-time communication or procedure, the generator is being operated in start-up, shutdown or testing mode. When a generator is in start-up mode it gradually increases its MW output and voltage control must be manually adjusted to keep pace until the generator reaches its minimum continuously sustainable load and can be synchronized to the interconnection.

Answer 115

To meet the voltage or Reactive Power Schedule. Feedback: Generator Voltage Schedule is how all generators work together to maintain power system voltages and schedules. Unless exempted by the Transmission Operator, each Generator Operator is required to maintain the generator voltage or Reactive Power schedule within each generating facility's capabilities.

Answer 116

Redistribute power flow to relieve the overloaded transmission line. Feedback: When power flow has reached or is exceeding its respective System Operating Limits, System Operators must try to redistribute the power flow to relieve the congested line. If the overload is severe, they may need to disconnect service to customers or load shed. Disconnecting equipment is discouraged in the power system.

Answer 117

Transmission Loading Relief. Feedback: Transmission Load Relief procedures use Power Transfer Distribution Factors to curtail transactions and reduce power flows. The Control Performance Standards calculation do not use Distribution Factors. The Interchange Distribution Calculator contains a matrix of line and transformer impedance's, it is a tool, and not a procedure. Outage Transfer Distribution Factors are used to determine the effects of transmission outages.

Answer 118

estimate the effect of an outaged transmission elements Feedback: Outage Transfer Distribution Factors help System Operators estimate the effect of outaged transmission elements. Power Transfer Distribution Factors estimates the effect of an Interchange Transaction on a specific flowgate. The answers 'determine the number of unexpected outaged elements...' and estimate the system operating limit...' are false and serve as distracters in this question.

Answer 119

generators could be adjusted to relieve the loading on the transmission lines. Feedback: Generation Shift Factors help System Operators determine which generators may be adjusted to relieve loading on transmission lines. Generator Shift Factors determine the amount of flow contribution that changes in output will have on identified transmission facilities.

Answer 120

When a generator with a negative shift factor increases its output, it relieves line loading. Feedback: When a generator with a negative shift factor increases its output, the power flow relieves line loading, typically because the generation increase is close to load.

Answer 121

Increase the Greenwood generator 200 MWs. Feedback: Positive Generator Shift Factors will increase loading on the specified line and negative Generator Shift factors will decrease loading. However, these directional signs must be considered when analyzing the direction of flow, shift factor direction and the relief needed.

Answer 122

determine which Interchange Transactions may be affecting a constrained path. Feedback: Power Transfer Distribution Factors help system operators determine if an Interchange Transaction may be affecting a constrained path. It is also used to determine if any of these transactions should be curtailed to relieve congestion. Outage Transfer Distribution Factors determine the effect of outage transmission elements. Generation shift Factors determine a generator's impact on a flowgate. Distribution or shift factors help System Operators determine power needs.

Answer 123

Contingency analysis tools. Feedback: Contingency Analysis tools use Line Outage Distribution Factors to predict how transmission line outages may affect loading on other lines. The other terms load ability calculator, market analysis and congestion management are tools that have other applications.

Answer 124

Increase the Grand River generator by 250 MWs. Feedback: There are many combinations that will provide the needed relief, including increasing the output of the generator that has a negative impact or shift factor and decreasing the generator that has the added impact or positive shift factor. Decreasing the St. Clair generators output by 100 MWs will provide 60 MWs of relief, not enough to relieve the overload. Decreasing the Grand River generator output will increase loading because of its negative shift factor and increasing output of the St. Clair generator will also increase load. The best of these options is to increase the output of the Grand river generator by 250 MWs to obtain the 100 MWs of relief. 100/0.4=250 MWs.

Answer 125

When a generator with a positive shift factor increases its output, it contributes to loading on the transmission line. Feedback: When a generator with a positive shift factor increases its output, the increased power flow will contribute to line loading.

Answer 126

Transmission lines exceeding their System Operating Limits. Feedback: System Operators must act when congested or overloaded transmission lines in their area have either reached or exceeded their System Operating Limits.

Answer 127

System loading, voltage, impedance Feedback: Reference: Transmission line limits are affected by system loading, voltage, and physical properties

Answer 128

Shunt capacitors Feedback: Reference: Shunt capacitors produce reactive power to support inductive loads while maintaining voltage. Capacitor output is best when voltage is 100%

Answer 129

Double bus, double breaker Feedback: Reference: The double bus, double breaker, configuration utilizes two buses and two breakers per circuit. Both buses are normally energized, and any circuit can be removed without an outage on the corresponding circuit. Failure of one bus will not interrupt a circuit because all circuits can be fed from the remaining bus. This configuration is expensive, requiring twice the equipment as a single bus scheme, but is highly reliable.

Answer 130

Electromagnetic induction Feedback: Reference: When a changing magnetic field is placed next to a coil of wire, voltage is produced. When alternating voltage is applied to a coil wire, a changing magnetic field is produced. Placing both coils of wire next to each other creates a transformer. Changing voltage on one side of the transformer creates voltage on the other side of the transformer.

Answer 131

Distribution of power at a more constant rate, increased efficiency and more economical Feedback: Reference: A three-phase system is more efficient and economical that a single-phase system.

Answer 132

Losses decrease by a factor of four Feedback: Reference: Power loss is current squared times resistance. Increasing voltage reduces current. Reducing current will reduce the power losses by a factor of four. Transformers in a power system are used to increase voltage and reduce current.

Answer 133

Isolation points through breakers and switches

Answer 134

5% greater than nominal and 5% less than nominal Feedback: Reference: The Transmission Operators' task is to control voltage and keep it within a plus or minus (+/-) 5% bandwidth during normal operations.

Answer 135

No Feedback: Reference: Total power is the square root of 9902 + 1002 which equals 995 MVA. This line is not overloaded.

Answer 136

A MW, MVAR, amp, voltage value that satisfies the most limiting of the prescribed operating criteria for a specified system configuration. Feedback: Reference: According to the NERC Glossary of terms for System Operating Limits, system Operating Limits are based upon certain operating criteria to ensure operation within acceptable reliability criteria.

Answer 137

160 MW Feedback: Reference: Power Transfer Distribution Factor, PTDF, is the percentage of electrical loading due to power flowing through the system. Power distribution is determined by transmission line property characteristics. In this problem, 80% PTDF for a 200 MW schedule means 160 MW will flow on Line X-Z.

Answer 138

Relay protection Feedback: Reference: Automated breaker operation protects the power system when certain conditions are met. Protective relays monitor system conditions, compare Real-time quantities against preset thresholds and react to abnormal conditions.

Answer 139

Resistance and reactance Feedback: Reference: Impedance is the square root of resistance squared plus reactance squared. The sum of inductance and capacitance is called reactance.

Answer 140

Deliver power from generators to consumer loads Feedback: Reference: Transmission lines are electricity's highways. The transmission system connects load to generation.

Answer 141

10 degrees Feedback: When the torque angle of the generator reaches approximately 10 degrees, it begins to supply power to the system. Torque angles of 30 to 60 degrees indicate that the generator is in full operation. If the generator torque angle reaches 90 degrees or more, the generator may experience a loss of synchronization causing instability in the system.

Answer 142

The excited (energized) field winding that rotates inside the stator to induce voltage into the stator winding and allows current to flow out of the stator when the generator is connected to the power grid. Feedback: The energized field windings of the rotor rotate inside the stator to induce voltage into the stator windings allowing current to flow out of the stator when the generator is connected to the power grid.

Answer 143

lead; raise Feedback: An inductive system tends to lower voltages and require more voltage support. Voltage leads current in an inductive system (ELI). A capacitive system tends to raise voltage, current leads voltage in a capacitive system (ICE).

Answer 144

90 degrees Feedback: Power angles above 90 degrees will lead to system instability.

Answer 145

All of the above. Feedback: When the power angle between two points on the power system increases to an angle of 90 degrees, or more, transient instability occurs. This is often the result of heavy power transfers on the system combined with a loss of generation.

Answer 146

All the above. Feedback: Reliability Coordinators and Transmission Operators may use a number of techniques to manage the impact of transmission outages. These include coordinating and adhering to voltage schedules, optimizing the use of LTC transformers, and verifying voltage control equipment are operating in automatic mode.

Answer 147

System Operating Limit Feedback: The System Operating Limit is the most limiting of the operating criteria for a specified system configuration that ensures it remains within acceptable reliability criteria. The Interconnection Reliability Operating Limit is a subset of the System Operating Limits that, if exceeded, could expose a widespread area of the Bulk Electric System to instability, uncontrolled separation or cascading outages.

Answer 148

frequency; decreases Feedback: When total generation in an Interconnection is less than the demand in the Interconnection, the Interconnection frequency decreases. Interconnection frequency reflects the balance of generation and load demand.

Answer 149

Setting appropriate voltage levels to withstand various contingencies. Feedback: System Operating Limits are determined by: setting appropriate voltage levels to withstand various contingencies. identifying equipment loading capabilities before excessive heat degrades their function and recognizing stability limitations.

Answer 150

voltage; frequency Feedback: The generator's ratings specify the voltage and frequency at which it can continue to operate safely. Operating at a frequency or voltage level that is outside its ratings will cause damage to the generator.

Answer 151

All the above Feedback: COM-001-2 requires the Reliability Coordinator, Transmission Operator, and Balancing Authority to have an Alternative Interpersonal Communication system. This system must be redundant to the Interpersonal Communications System and not use the same infrastructure as the day-to-day Interpersonal Communication system.

Answer 152

Satellite phone and a cell phone Feedback: NERC glossary of terms, Alternative Interpersonal Communications definition. Any Interpersonal Communication that is able to serve as a substitute for and does not utilize the same infrastructure (medium) as, Interpersonal Communication used for day-to-day operation. A satellite phone and a cell phone would not utilize the same infrastructure as the normal day-to-day Interpersonal Communications system.

Answer 153

Control Centers within the same functional entity Feedback: The Reliability Coordinator, Transmission Operator, and Balancing Authority shall test their Alternative Interpersonal Communication capability at least once each calendar month. If the test is unsuccessful, the responsible entity shall initiate action to repair or designate a replacement Alternative Interpersonal Communication capability within 2 hours. Examples of Alternative Communications are Satellite phone, radio systems, or any other documented designated telecommunications capability.

Answer 154

Investigate and recommend solutions to internal and external telecommunications problems. Feedback: Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall provide a means to coordinate telecommunications among their respective areas. This coordination shall include the ability to investigate and recommend solutions to telecommunications problems within the area and with other areas.

Answer 155

English Feedback: Unless agreed to otherwise each Reliability Coordinator, Transmission Operator, and Balancing Authority shall use English as the language for all communications between and among operating personnel responsible for the real-time generation and operation of the Interconnected Bulk Electric System.

Answer 156

Redundancy Feedback: Definition of the Alternative Interpersonal Communication. Any Interpersonal Communication that is able to serve as a substitute for and does not utilize the same infrastructure (medium) as, Interpersonal Communication used for day-to-day operation.

Answer 157

Tested and/or actively monitored Feedback: Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall manage, alarm, test and/or actively monitor vital telecommunications facilities.

Answer 158

Reliability Feedback: Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall provide adequate and reliable telecommunications facilities [for] the exchange of Interconnection and operating information.

Answer 159

Other Reliability Coordinators, Transmission Operators, and Balancing Authorities. Feedback: Reliability Coordinators are required to have Interpersonal and Alternative Interpersonal Communication capability with Transmission Operators and Balancing Authorities in their RC area and with adjacent Reliability Coordinators.

Answer 160

Equipment not used for routine communications Feedback: Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall manage, alarm, test and/or actively monitor vital telecommunications facilities. Special attention shall be given to emergency telecommunications facilities and equipment not used for routine communications. Emergency and alternative facilities should receive special attention because it is easy to overlook equipment that is not normally used. Since they may be the facilities of last resort, it is important that they be available when needed.

Answer 161

One (1) hour Feedback: COM-002, Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall notify entities respectively within 60 minutes of the detection of a failure of its Interpersonal communication capability that lasts 30 minutes or longer.

Answer 162

Initiate action to repair or designate a replacement Alternative Interpersonal Communication system capability within 2 hours. Feedback: COM-001, Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall test its Alternative Interpersonal Communication capability (TRE1) at least once each calendar month. If the test is unsuccessful, the responsible entity shall initiate action to repair or designate a replacement Alternative Interpersonal Communication capability within 2 hours.

Answer 163

Request that the Reliability Coordinator reissue the Operating Instruction. Feedback: NERC Standard COM-002-4 R6 R6 requires each Balancing Authority, Distribution Provider, Generator Operator, and Transmission Operator who during an emergency, receives an oral two-party, person-to-person Operating Instruction, excluding written or oral single-party to multiple party burst Operating Instructions, request that the issuer reissue the Operating Instruction.

Answer 164

Operating Instructions Feedback: R1 requires each Transmission Operators, Balancing Authority, and Reliability Coordinator to develop documented communications protocols for its operating personnel who issue and receive Operating Instructions.

Answer 165

Not necessarily verbatim as long as the major components of the Operating Instruction are repeated correctly. Feedback: R6 requires each Balancing Authority, Distribution Provider, Generator Operator, and Transmission Operator who during an emergency, receives an oral two-party, person-to-person Operating Instruction, excluding written or oral single-party to multiple party burst Operating Instructions to either: Repeat, not necessarily verbatim, the Operating Instruction, and receive confirmation from the issuer that the response was correct, or Request that the issuer reissue the Operating Instruction.

Answer 166

Required to confirm or verify that the Operating Instruction was received by at least one receiver of the all call Operating Instruction. Feedback: R7 requires each Balancing Authority, Reliability Coordinator, and Transmission Operator who during an emergency, issues a written or oral single-party to multiple-party burst Operating Instruction to confirm or verify that the Operating Instruction was received by at least one receiver of the Operating Instruction. A one-way single party to multiple-arty burst can be defined as an "All-Call" messaging system.

Answer 167

Repeat the original statement to resolve any misunderstandings. Feedback: R5 requires each Reliability Coordinator, Transmission Operator and Balancing Authority who during an emergency, issues an oral two-party, person-to-person Operating Instruction, excluding written or oral single-party to multiple-party burst Operating Instructions, to either: Confirm the receiver's response if the repeated information is correct reissue the Operating Instruction if the repeated information is incorrect or if requested by the receiver, or take an alternative action if a response is not received or if the Operating Instruction was not understood by the receiver.

Answer 168

Use the English language unless agreed to otherwise. Specify nomenclature for transmission interface Elements and Facilities. Feedback: Requirement R1.1 The protocols must require operating personnel who issue and receive an oral or written Operating Instruction to use the English language, unless agreed to otherwise. Requirement R1.6 The protocols must specify the nomenclature for Transmission interface Elements and Transmission interface Facilities when issuing an oral or written Operating Instruction.

Answer 169

All apply Feedback: Element 1.2: The protocols must require operating personnel that Issue an oral two-party, person-to-person operating Instruction take one of the following actions: Confirm the receiver's response if the repeated information is correct. Reissue the Operating Instruction if the repeated information is incorrect or if requested by the receiver. Take an alternative action if a response is not received or if the Operating Instruction was not understood by the receiver.

Answer 170

Assess adherence to the documented communication protocols in Requirement R1 by its operating personnel who issue and receive Operating Instructions. Provide feedback to those operating personnel and take corrective action, as deemed appropriate by the entity, to address deviations from the documented protocols. Assess the effectiveness of its documented communications protocols for its operating personnel who issue and receive Operating Instructions and modify its documented communication protocols, as necessary. Feedback: R4 requires each Reliability Coordinator, Balancing Authority, and Transmission Operator to assess adherence to, and the effectiveness of its documented communications protocols at least once every twelve (12) calendar months. 4.1 Assess adherence to the documented communications protocols in Requirement R1 by its operating personnel who issue and receive Operating Instructions, provide feedback to those operating personnel and take corrective action, as deemed appropriate by the entity, to address deviations from the documented protocols. 4.2 Assess the effectiveness of its documented communications protocols in Requirement R1 for its operating personnel who issue and receive Operating Instructions and modify its documented communication protocols, as necessary.

Answer 171

All apply Feedback: R2 states that each RC, BA, and TOP shall conduct initial training for each of its operating personnel responsible for the Real-time operation of the interconnected Bulk Electric System on their documented communication protocols that were developed in Requirement R1 prior to that individual operator issuing an Operating Instruction. R3 states that each Distribution Provider and Generator Operator shall conduct initial training for each of its operating personnel who can receive an oral two-party, person-to-person Operating Instruction prior to that individual operator receiving an oral two-party, person-t-person Operating Instruction.

Answer 172

Use English language, unless agreed to otherwise. Specify instances that require time identification when issuing an oral or written Operating Instruction and the format for that time identification. Feedback: NERC Standard COM-002-4 R1.1 The protocols must require operating personnel who issue and receive an oral or written Operating Instruction to use the English language, unless agreed to otherwise. An alternate language may be used for internal operations. R1.5 The protocols must specify instances that require time identification when issuing an oral or written Operating Instruction and the format for that time identification.

Answer 173

A command by operating personnel responsible for the Real-time operation of the interconnected Bulk Electric System to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of Bulk Electric System. Feedback: The NERC glossary of terms defines an Operating Instruction as: A command by operating personnel responsible for the Real-time operation of the interconnected Bulk Electric System to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of Bulk Electric System. A discussion of general information and of potential options or alternatives to resolve Bulk Electric System operating concerns is not a command and is not considered an Operating Instruction.

Answer 174

Prior to that individual operator receiving an oral two-party, person-to-person Operating Instruction. Feedback: A Balancing Authority that is experiencing an operating capacity or energy emergency shall communicate its current and future system conditions to its Reliability Coordinator and neighboring Balancing Authorities.

Answer 175

The issuance of an Operating Instruction from one party to another. The repeat back of the Operating Instruction by the receiving party. The acknowledgement by the issuing party that the Operating Instruction was repeated back correctly or, if not, reissuing the Operating Instruction again. Feedback: Three-Part Communication gets its name from the three distinct parts of the process: Issuing an Operating Instruction from one party to another. Repeat back of the Operating Instruction by the receiving party. Acknowledgement by the issuing party that the Operating Instruction was repeated back correctly or, if not, reissuing the Operating Instruction again.

Answer 176

To detect SOL violations and predict what might happen on the power system Feedback: Real-time Contingency Analysis (RTCA) tools are used to improve the Situational Awareness for System Operators of contingencies that may impact the operating area. The Transmission Operator uses the results of these analyses to immediately mitigate the SOL violation.

Answer 177

All of the answers are correct. Feedback: Facility outages will change the power flow on the power system. When an element is unavailable another element will pick up the load to deliver power as needed.

Answer 178

To simulate accurate power flows and contingency analysis results Feedback: External network model data that will significantly affect the power flows and contingency analysis results in system should be part of the data specification.

Answer 179

Transmission status MW output MVAR output Generator status Feedback: Power Flow consists of MW and MVAR output. Availability of generation and transmission asset determines how much power can be produced or transported reliably.

Answer 180

List of data needs and the periodicity for providing data. Feedback: Each Transmission Operator maintains a data specification document that specifies a list of data, the periodicity for providing data, and deadlines to provide the indicated data.

Answer 181

2 and 4 Feedback: NERC Standard TOP-003 states that the Transmission Operator and Balancing Authority have data needed to fulfill their operational and planning responsibilities.

Answer 182

To predict operations. To identify constraints. Feedback: System studies are used to identify constraints and predict operations. Predicting system operation allows for Situation Awareness and mitigation of problems before they happen.

Answer 183

Mutually agreeable security protocol. Mutually agreeable format. Feedback: Each System Operator receiving a data specification shall satisfy the obligations of the documented specifications using: A mutually agreeable format A mutually agreeable process for resolving data conflicts. A mutually agreeable security protocol.

Answer 184

Transmission Operators, Balancing Authorities, and Reliability Coordinators Feedback: Transmission Operators, Balancing Authorities, and Reliability Coordinators work together and perform tasks such as: Monitoring transmission and generation resource availability Reviewing generation output continuously Reviewing transmission power flows continuously Monitoring Interconnection frequency

Answer 185

Analysis functions Real-time monitoring

Answer 186

Criteria for evaluating the quality of Real-time data

Answer 187

Transmission Operators Balancing Authority

Answer 188

mitigate the effects of analysis tools outages. Feedback: NERC Standard IRO-002 gives each Reliability Coordinator the authority to approve planned outages and maintenance of analysis tools; including, approvals for planned maintenance. In practice if an outage is necessary that effects their ability to analyze the state of their power system, the RC should have a procedure in place that mitigates the effects of analysis tool outages.

Answer 189

Real-time Assessments Feedback: NERC Standard IRO-002: Each Reliability Coordinator shall have data exchange capabilities with its Transmission Operators and Balancing Authorities, and with other entities it deems necessary for it to Operational Planning Analyses. Communication and data exchange capabilities are required to meet reliability need of the interconnection.

Answer 190

SOL and IROL exceedances are identified. Feedback: Each Reliability Coordinator shall have detailed real-time monitoring capability of its Reliability Coordinator Area and sufficient monitoring capability of its surrounding Reliability Coordinator Areas to ensure that potential or actual System Operating Limit or Interconnection Reliability Operating Limit violations are identified.

Answer 191

System Operating Limit Feedback: System Operating Limit: The value (such as MW, MVAR, Amperes, Frequency, or Volts) that satisfies the most limiting of the prescribed operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria. System Operating Limits are based upon certain operating criteria.

Answer 192

To improve the reliability of the Bulk Electric System. Feedback: EOP-004: Purpose: to improve the reliability of the Bulk Electric System by requiring the reporting of events by Responsible Entities.

Answer 193

All answers are correct. Feedback: EOP-004: Event reporting and subsequent analysis, assist in providing lessons learned and to implement corrective actions to minimize a repeat in the future. The lessons learned lead to recommendations for corrective actions by involved parties in the incident. Some recommendations may apply to all parties, not only those involved in the event. Upon implementation of the actions, the recurrence is greatly reduced.

Answer 194

A Balancing Authority making a public appeal for load reduction due to abnormally hot temperatures and expected Energy Emergency.

Answer 195

All apply Feedback: Each of the answers would categorize as a reportable event if the threshold identified in Attachment 1 of EOP-004 were exceeded. For example: For a BES emergency requiring the manual shedding of firm load to be a reportable event, 100 MWs or more would have to be shed.

Answer 196

If analysis capability was unavailable for more than 30 minutes, an event report must be submitted. Feedback: EOP-004, Attachment 1: Reportable Events The reporting threshold for loss of monitoring capability affecting a control center such that analysis capability is rendered inoperable is 30 continuous minutes or more. There is not enough information to suspect sabotage

Answer 197

It is a reportable event and the Balancing Authority must report it to NERC by the end of the next business day, which would be Thursday at 4:00 p.m. local time. Feedback: EOP-004, Attachment 1 Separation of part of the system resulting in islanding of 100 MWs or more is a reportable event regardless of how long the islanding lasts. R2: Each Responsible Entity shall report events specified in EOP-004-4 Attachment 1 to the entities specified per their event reporting Operating Plan by the later of 24 hours of recognition of meeting an event type threshold for reporting or by the end of the Responsible Entity’s next business day (4 p.m. local time will be considered the end of the business day).

Answer 198

An under-voltage event resulting in automatic load shed of 125 MWs. Feedback: EOP-004, Attachment 1: Reportable Events Loss of generation must exceed 1,000 MWs in ERCOT or 2,000 in the Eastern or Western Interconnections There is no reporting threshold on frequency. However, if part of the system separates into an island of 100 MWs or more, that would be reportable. A loss of firm load must be at least 200 MWs or 300 MWs, depending on the entities previous years' demand. Automatic or manual load shed of 100 MWs or more is reportable, regardless of the cause.

Answer 199

Until the end of business the following Monday. Feedback: EOP-004: Each Responsible Entity shall report events specified in EOP-004-4 Attachment 1 to the entities specified per their event reporting Operating Plan by the later of 24 hours of recognition of meeting an event type threshold for reporting or by the end of the Responsible Entity’s next business day (4 p.m. local time will be considered the end of the business day).

Answer 200

Take the appropriate action to return the system to within normal limits Inform the Reliability Coordinator

Answer 201

It results in safety concerns or environmental violations

Answer 202

Real-time Operating personnel command to change or preserve the state of an element of the BES

Answer 203

Initiate its Operating Plan to mitigate the SOL exceedance

Answer 204

Its IROL Tv

Answer 205

A Real-time Assessment of the transmission facility outage is completed

Answer 206

Change the output of generators Reduce Interchange Shed load

Answer 207

Instability, uncontrolled separation, or cascading outages

Answer 208

The Reliability Coordinator will then evaluate actions being taken and direct additional corrective actions as needed

Answer 209

Interruption of power to a large part of the BES

Answer 210

At least once every 30 minutes

Answer 211

Notify the Reliability Coordinator and known impacted entities of the outage

Answer 212

30 minutes

Answer 213

Operating Instruction

Answer 214

Use the Transmission Operator's limit and conduct another study

Answer 215

Remedial Action Scheme (RAS)

Answer 216

BES Facilities within its TOP area Non-BES facilities within its TOP area identified as necessary Status, voltage, and flow data outside its TOP area identified as necessary Status of Remedial Action Schemes in its TOP area

Answer 217

Your Reliability Coordinator and any Transmission Operators or Balancing Authorities that may be impacted by the outage.

Answer 218

Status of Remedial Action Schemes that impact generator or load

Answer 219

Inform the Reliability Coordinator of actions taken

Answer 220

Operational Planning Analysis

Answer 221

The requesting TOP has also implemented emergency actions

Answer 222

Thermal Angle stability Voltage

Answer 223

Safety, equipment, regulatory requirements Feedback: Transmission Operators, Balancing Authorities, Generator Operators, Distribution Providers must comply with Reliability Coordinator Operating Instructions unless such actions would violate safety equipment, or regulatory or statutory requirements.

Answer 224

Monitor System Facilities in its RC area and determine any SOL or IROL violations Feedback: A Reliability Coordinator monitors Bulk Electric System facilities and must be able to determine any potential System Operating Limit and Interconnection Reliability Operating Limit violation within its Reliability Coordinator Area and direct actions to mitigate limit exceedance. Bulk Electric System is defined as all equipment connected to 100 kV and above facilities. Reliability Coordinators would not monitor system facilities below 100 kV unless critical to system reliability.

Answer 225

Re-dispatch generation, reduce interchange or shed load Feedback: Corrective Actions include: Re-dispatch generation which includes starting combustion turbines Curtailing schedules Shedding load

Answer 226

Contingency analysis capabilities Feedback: Wide-Area view is necessary for monitoring a Reliability Coordinator area and each Reliability Coordinator shall have adequate analysis tools; such as state estimation and contingency analysis capabilities (thermal, stability, and voltage) to be aware of what might happen in a pre- and post- contingency situation.

Answer 227

Lower transfers across area and increase generation in area with low voltage. Feedback: Low voltage is a result of insufficient reactive power and high losses associated with transferring power to load areas. Increasing generation in the area with low voltage reduces losses associated with transferring power. Starting generation will also increase the reactive power supply.

Answer 228

Reliability Coordinator Feedback: The Reliability Coordinator function was established to facilitate coordination and to provide entities with the "big picture" view of the system.

Answer 229

Issuing an Operating Instruction per the Operating Procedure Feedback: Operating Procedure - A document that identifies specific steps or tasks that should be taken by one or more specific operating positions to achieve specific operating goal(s). The steps in an Operating Procedure should be followed in the order in which they are presented and should be performed by the position(s) identified. (NERC Glossary of Terms).

Answer 230

Immediately contact Reliability Coordinator B to discuss options. Feedback: Since this particular line is critical to the reliability of the Bulk Electric System in both regions, both Reliability Coordinator A and Reliability Coordinator B would immediately discuss the actions that needed to be taken. Regardless of the scenario, or situation, both Reliability Coordinators work very closely together in the resolution of a very potential problem.

Answer 231

Both Reliability Coordinators should have Operating Procedures, processes, or Plans to address voltage control issues on the line. Feedback: The Reliability Coordinator shall have Operating Procedures, Processes, or Plans in place for activities that require notification, exchange of information or coordination of actions with one or more other Reliability Coordinators to support Interconnection reliability. These Operating Procedures, Processes, or Plans shall address scenarios that affect other Reliability Coordinator Areas as well as those developed in coordination with other Reliability Coordinators. An area that must be addressed is Voltage control, including the coordination of reactive resources for voltage control.

Answer 232

Do not allow the outage to proceed.

Answer 233

Discuss with impacted RC and postpone outage

Answer 234

Implement the agreed upon solution and notify the involved Reliability Coordinators. Feedback: The Reliability Coordinators must agree on the problem and actions to take to prevent or mitigate the problem and implement the agreed upon solution and ensure that the involved Reliability Coordinators are aware of the actions.

Answer 235

Opening the low voltage transmission line. Feedback: If the involved Reliability Coordinators cannot agree on the solution, the more conservative solution shall be implemented.

Answer 236

Unexpected failure of a system component.

Answer 237

Percentage change of loading on transmission due to generator output changes.

Answer 238

260 MW Feedback: 200 x .3 = 60 plus the 200 already on Line C

Answer 239

Contingency Analysis

Answer 240

Re-dispatch, reconfigure, reduce

Answer 241

Percentage of change of electrical power transfer when a facility is removed from service.

Answer 242

Percentage change of electrical loading on a line due to change in power transfers from one area to another.

Answer 243

Reschedule the outage for a later date.

Answer 244

Develop an Operating Plan to mitigate the emergency

Answer 245

All the above

Answer 246

A process identified by each Interconnection to relieve loading on the transmission system caused by power transfers across areas

Answer 247

Contact their Reliability Coordinator and discuss mitigation options. Feedback: The question does not indicate the direction of power flow or if this is the deficient Balancing Authority. Therefore, you cannot assume that bringing on generation will help. It may further load the transmission line.

Answer 248

Ensure real and reactive resources are sufficient to meet demands. Identify potential SOLs. Feedback: An Operational Planning Study must be completed so each Transmission Operator can assess whether the planned actions for the next-day will exceed any of its SOLs. The study will also ensure real and reactive resources are sufficient to meet demands.

Answer 249

Create Operating Plans that will mitigate the predicted issues. Feedback: An Operating Plan is required to be created to document the identified group of activities that may be used to achieve some goal. An Operating Plan may contain Operating Procedures and Operating Processes. The plan will require a strategy and coordinator among the impacted entities

Answer 250

Create an operating plan Feedback: The Transmission Operator should specify the data needed to have sufficient information and analysis to determine the cause(s) of SOL violations. This analysis shall be conducted in all operating time frames. The Transmission Operator shall use the results of these analyses to immediately mitigate the SOL violation.

Answer 251

Ensure generator resources are sufficient to meet demand. Feedback: Each Balancing Authority shall notify entities identified in the Operating Plan(s) that address expected generation resource commitment and dispatch, Interchange scheduling, Demand patterns, and capacity/energy reserve requirements as to their role in those plan(s).

Answer 252

Perform a Real-time assessment Feedback: Operational Planning Analysis is an evaluation of projected system conditions to assess anticipated (pre-Contingency) and potential (post-Contingency) conditions for next-day operations. Real-time Assessment is also an evaluation of system conditions using Real-time data to assess existing (pre-Contingency) and potential (post-Contingency) operating conditions. A TOP would need to perform future analysis or current assessments of current conditions.

Answer 253

Operational Planning Analysis Feedback: Operational Planning Analysis is an evaluation of projected system conditions to assess anticipated (pre-contingency) and potential (post-contingency) conditions for next-day operations. The evaluation shall reflect applicable inputs including, but not limited to, load forecasts, generation output levels, Interchange, know Protection System and Special Protection System status or degradation, transmission outages, generator outages, Facility Ratings, and identified phase angle and equipment limitations.

Answer 254

Entities that have a role in utilizing the plan and the Reliability Coordinator. Feedback: Each Transmission Operator shall notify entities identified in the Operating Plan(s) developed as to their role in those plans as well as the Reliability Coordinator.

Answer 255

Generation resource commitments Interchange schedules Feedback: Generation resources commitment and dispatch, Interchange schedules, demand pattern, and capacity and energy reserve requirements all must be included in the next day operating plans.

Answer 256

30 minutes Feedback: A N-1 Contingency will be part of the study process to Identify that following and unplanned outage or other event that may result in a System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) violation. If a SOL or IROL exceedance occurs then the Transmission Operator must return its transmission system to within IROL as soon as possible, but no longer than 30 minutes.

Answer 257

Wye connected transformers Feedback: GICs enter a transformer through its ground connection, producing an off-setting DC excitation current. Delta connected transformers do not have a ground connection and therefore are not susceptible to GICs.

Answer 258

Geomagnetically Induced Currents Feedback: Geomagnetically Induced Currents (GICs) caused by Earth Surface Potentials (ESP) can enter the power system through grounded connections, causing an effect on the power system. Note: GMDs and the GICs they produce can cause a loss of Reactive Power, not an excess.

Answer 259

Overheating in some transformer cores Feedback: Wye-connected transformers are susceptible to Geomagnetically Induced Currents (GICs) entering through the grounded connections. These currents can result in saturation of the transformer core causing excessive heating. EOP-010 is only applicable to Reliability Coordinators and Transmission Operators with transformers with a high side wye-grounded winding greater than 200 kV.

Answer 260

All apply Feedback: In a severe GMD, all of the conditions listed could occur.

Answer 261

Transformer(s) with high side wye-grounded winding 200 kV and above Feedback: EOP-010, Applicability 4.1. Functional Entities: 4.1.1 Reliability Coordinator 4.1.2 Transmission Operator with a Transmission Operator Area that includes a power transformer with a high side wye-grounded winding with terminal voltage greater than 200 kV

Answer 262

Isolate equipment susceptible to damage, such as transformers Start off-line generation and/or return outage equipment to service Reduce system voltage to allow transformers to operate further from saturation Feedback: Starting off-line generation and returning outage equipment to service, reducing system voltage to allow transformers to operate further from saturation, and isolating equipment susceptible to damage are all strategies that should be considered when developing a GMD Operating Procedure or process based on your geographic location and system characteristics. Operating generators at maximum Real and Reactive Power output is not a strategy to consider when developing a GMD Operating Procedure or Process. Removing grounds from all grounded equipment is not a feasible option.

Answer 263

The Reliability Coordinator Feedback: EOP-010 states the Reliability Coordinator is responsible for disseminating space weather information to all entities identified in their GMD Operating Plan. This standard is only applicable to Reliability Coordinators and select Transmission Operators.

Answer 264

Specify actions to be included in the Transmission Operator's GMD Operating Procedures Feedback: Reliability Coordinators are responsible for coordinating the GMD Operating Procedures of the Transmission Operators, disseminating information concerning GMDs to entities, and identifying conflicts in their area's Transmission Operators plans. They are not responsible for specifying actions to be included in the Transmission Operators GMD Operating Procedures.

Answer 265

K-7 or higher Feedback: Most electrical power systems are not affected by geomagnetic activity level below K-7.

Answer 266

Define steps or tasks on receiving space weather information Actions to be taken by System Operators based on predetermined conditions Conditions for terminating the Operating Procedure or Process Feedback: EOP-010 is also applicable to Transmission Operators with a Transmission Operator Area that includes a power transformer with a high side wye-grounded winding with terminal voltage greater than 200 kV. If a Transmission Operator falls into this category, they are required to develop, maintain, and implement a GMD Operating Procedure or Operating Process to mitigate the effects of GMD events on the reliable operations of their respective system. The procedure or process must include at least the following: Defined steps or tasks on receiving space weather information Actions to be initiated by System Operators based on predetermined conditions for terminating the Operating Procedure or Operating process This requirement allows each Transmission operator to design procedures or processes based on their assessment of entity-specific factors, such as geography, geology, and topology.

Answer 267

grounded Feedback: Geomagnetically Induced Currents (GICs) enter the bulk power system through grounded equipment when the impedance of the earth is higher than the impedance of the transmission line. While they may cause some equipment to become isolated, they do not enter the power system through isolated equipment. The most common point to see GICs entering the power system are through Wye connected transformers.

Answer 268

System Restoration Feedback: A document that identifies a group of activities that may be used to achieve some goal. An Operating Plan may contain Operating Procedures and Operating Processes. A company-specific system restoration plan that includes an Operating Procedure for black-starting units, Operating Processes for communicating restoration progress with other entities, etc., is an example of an Operating Plan.

Answer 269

Develop an operating plan Feedback: To address the effects of operating Emergencies by ensuring each Transmission Operator and Balancing Authority has developed Operating Plan(s) to mitigate operating Emergencies, and that those plans are coordinated within a Reliability Coordinator Area.

Answer 270

System Operating Limit (SOL) exceedance System Restoration Capacity deficiency Feedback: All selections except failure of Alternative Interpersonal Communication Equipment would be considered an operational emergency. Per COM-001, Alternative Interpersonal Communication Equipment must be tested monthly, and if found to be inoperative, replaced or repaired within two hours, but this would not be considered an operational emergency.

Answer 271

1, 2, 3 are needed in an Operating Plan and the Reliability Coordinator will review for compatibility and inter-dependency and coordination Feedback: The Reliability Coordinator shall review the Operating Plan(s) to mitigate operating Emergencies submitted by a Transmission Operator or a Balancing Authority regarding any reliability risks that are identified between Operating Plans. The Reliability Coordinator will review each submitted Operating Plan(s) on the basis of compatibility and inter-dependency with other Balancing Authorities’ and Transmission Operators’ Operating Plans and review each submitted Operating Plan(s) for coordination to avoid risk to Wide Area reliability.

Answer 272

Role and responsibilities for activating the Operating Plan should be identified in document S-O-P 14. Feedback: Each Transmission Operator shall develop, maintain, and implement one or more Reliability Coordinator-reviewed Operating Plan(s) to mitigate operating Emergencies in its Transmission Operator Area, including Roles and responsibilities for activating the Operating Plan(s)

Answer 273

Discuss with the Reliability Coordinator and initiate an Energy Emergency Alert Level 1 Feedback: Energy Emergency Alerts should be issued when the Balancing Authority realizes that all their resources are committed to native load. While they may still have resources, the Balancing Authority is one contingency away from having to use their reserves and possible Shed Load. The Reliability Coordinator will assist the Balancing Authority by declaring the Energy Emergency Alert and looking for reserves within its area.

Answer 274

Energy Emergency Alerts is an Operating Process to maintain generation-load balance in emergency conditions. Feedback: Attachment 1 - EOP-011 provides the process and descriptions of the levels used by the Reliability Coordinator in which it communicates the condition of a Balancing Authority which is experiencing an Energy Emergency.

Answer 275

The Reliability Coordinator will declare the Energy Emergency Alerts and obtain assistance Feedback: Each Reliability Coordinator that has a Balancing Authority experiencing a potential or actual Energy Emergency within its Reliability Coordinator Area shall declare an Energy Emergency Alert. The Balancing Authority will discuss their emergency situation and have Operating Plans for Energy Emergencies in place. The Reliability Coordinator will assist the Balancing Authority and request assistance as needed from other Balancing Authorities and Transmission Operator in their Reliability Coordinator Area and neighboring Reliability Coordinators.

Answer 276

The Reliability Coordinator will notify the Balancing Authorities and Transmission Operators within its RC Area within 30 minutes Feedback: Each Reliability Coordinator that receives an Emergency notification from a Transmission Operator or Balancing Authority within its Reliability Coordinator Area shall notify, within 30 minutes from the time of receiving notification, other Balancing Authorities and Transmission Operators in its Reliability Coordinator Area, and neighboring Reliability Coordinators.

Answer 277

Shed Load to reduce flow on heavily loaded lines Feedback: Each Transmission Operator shall develop, maintain, and implement one or more Reliability Coordinator-reviewed Operating Plan(s) to mitigate operating Emergencies in its Transmission Operator Area. Load Shedding tools and when to use them would be part of the Operating Plan to mitigate a low voltage situation.

Answer 278

as requested Feedback: EOP-005, R12: Each Transmission Operator shall participate in its Reliability Coordinator's restoration drills, exercises, or simulations as requested by its Reliability Coordinator.

Answer 279

Through Contingency Analysis Feedback: EOP-005, R6: Each Transmission Operator must verify through analysis of actual events, steady state and dynamic simulations, or testing, that the System Restoration Plan accomplishes the intended function. This verification is to be completed at least once every five (5) years at a minimum.

Answer 280

Transmission Operator (TOP) Feedback: EOP-005, R1: Each Transmission Operator is required to have a dated and documented System Restoration Plan, approved by its Reliability Coordinator, to re-establish its electric system in a stable and orderly manner in the event of a partial or total shutdown of its system.

Answer 281

Annually Feedback: EOP-005, R3: Each Transmission Operator is required to review their restoration plan and submit it to their Reliability Coordinator annually on a mutually agreed upon schedule. If there are no changes to the previous restoration plan, then the Transmission Operator only needs to confirm annually, on a predetermined schedule, with the Reliability Coordinator that it has been reviewed.

Answer 282

All apply Feedback: EOP-005, R10: to assure the proper execution of the System Restoration plan, each Transmission Operator must provide a training program for their System Operators. The annual training material must include: The System Restoration Plan, including coordination with the Reliability Coordinator and the Generator Operators included in the restoration plan Restoration priorities Building cranking paths Synchronizing (the re-energized sections of the System)

Answer 283

False Feedback: EOP-005, R15: Each Generator Operator with a Blackstart Resource shall notify its Transmission Operator of any known changes to the capabilities of that Blackstart Resource affecting the ability to meet the Transmission operator's restoration plan within 24 hours following such change.

Answer 284

Reliability Coordinator Area Feedback: EOP-006, R1: In the event of a partial or total shutdown of its system, it is important for each Reliability Coordinator to have a Reliability Coordinator Area restoration plan in place to reestablish its electric system in a stable and orderly manner. The restoration plan must include operating instructions and procedures to cover emergency conditions and the loss of vital telecommunications channels. The scope of the Reliability Coordinator's restoration plan should begin when Blackstart Resources are utilized to re-energize a shutdown area of the Bulk Electric System (BES) or when a separation has occurred between neighboring Reliability Coordinators, or an energized island has been formed on the BES within the Reliability Coordinator Area. The scope should end when all of its Transmission operators are interconnected, and the Reliability Coordinator's Area is once again connected with all of its neighboring Reliability Coordinator Areas.

Answer 285

30 Feedback: EOP-006, R4: Each Reliability Coordinator must review its neighboring Reliability Coordinator's Restoration Plan(s) to ensure there are no conflicts between its restoration plan and any of its neighbors. On the occasion a conflict is found, the conflict must be resolved within thirty (30) calendar days.

Answer 286

Its Balancing Authority Feedback: EOP-006, R2: The Reliability Coordinator shall distribute its most recent Reliability Coordinator Area restoration plan to each of its Transmission Operators and neighboring Reliability Coordinators within 30 calendar days of creation or revision.

Answer 287

All of the above Feedback: EOP-006, R1: The Reliability Coordinator's Restoration Plan must include the following elements: A high- level strategy for restoring the Interconnection Operating processes for restoring the Interconnection Coordination with Transmission Operators and their restoration plans Coordination with neighboring Reliability Coordinators and their restoration plans Criteria and conditions for reestablishing interconnections with Transmission Operators and Reliability Coordinators in their own area as well as in other Reliability Coordinator's Area. Reporting requirements for entities within the areas during a restoration event Criteria for sharing information with neighboring Reliability Coordinators, Transmission Operators, and Balancing Authorities in its area Identification of the Reliability Coordinator as the primary contact for disseminating restoration information within its area and in neighboring areas Criteria for transferring operations and authority back to the Balancing Authority

Answer 288

annual System Restoration training Feedback: EOP-006, R9: Each Reliability Coordinator shall include within its operations training program, annual System Restoration training for its System Operators to assure the proper execution of its restoration plan.

Answer 289

two Feedback: EOP-006, R 10: Each Reliability Coordinator shall conduct two System Restoration drills, exercises, or simulations per calendar year. This shall include the Transmission Operators and Generator Operators as dictated by the particular scope of the drill, exercise or simulation that is being conducted.

Answer 290

All the above Feedback: EOP-008, R1: Possible scenarios which may result in the implementation of an Operating Plan for backup functionality include fire alarm or fire, bomb threat or detonation, biohazard warning or incident, civil unrest development or occurrence, or adverse weather conditions. Total loss of ICCP communication would render the ability to monitor and perform analysis on the system for reliability purposes and would constitute implementing the Operating Plan as well.

Answer 291

True Feedback: EOP-008: Each entity must have primary and backup functionality that do not depend on each other for the control center functionality required to maintain compliance with Reliability Standards.

Answer 292

All apply Feedback: EOP-008, R1.2: In many scenarios, data and communications infrastructure may remain functional; however, the Operating Plan for backup functionality must include a summary description of the elements required to support backup functionality, including: Tools and applications to ensure that System Operators have situational awareness of the BES Data communications Voice communications Power source(s) Physical and cyber security

Answer 293

Location providing backup functionality Primary Control Center Feedback: EOP-008, R2: each RC, BA, and TOP shall have a copy of its current Operating Plan for backup functionality available at its primary control center and at the location providing backup functionality.

Answer 294

Annually Feedback: EOP-008, R5: Each Reliability Coordinator, Balancing Authority, and Transmission Operator shall annually review and approve its Operating Plan for backup functionality. 5.1. An update and approval of the Operating Plan for backup functionality shall take place within sixty calendar days of any changes to any part of the Operating Plan described in Requirement R1.

Answer 295

Monitoring, control, logging, and alarming Feedback: EOP-008, R4: Each Balancing Authority and Transmission Operator must have backup functionality that includes monitoring, control, logging, and alarming.

Answer 296

Geomagnetic induced current enter the power system and cause abnormal operations Feedback: GICs are primarily direct current induced in the AC system, distorting the magnetic characteristics. GICs enter the power grid through the grounded of a transformer's why side when the impedance of the ground is higher than the impedance of the transmission line, since current flow follows the path of least impedance. High voltage transmission systems have low impedance which allows the GIC flow on the system to increase.

Answer 297

Enable personnel to effectively coordinate and re-establish the interconnection Feedback: Restoration plans must be established. These plans prepare personnel for effective coordination of the system restoration process. The goal is to methodically restore the power system and re-establish the Interconnection.

Answer 298

Develop an Operating Plan to mitigate the emergency Feedback: To maintain reliability the system operator should evaluate system conditions and develop an operating plan when they perform mitigating actions. The operating plan should include notifications, roles and responsibilities, and actions to be performed.

Answer 299

Current or pre-determined operating situation that create a reliability concern Feedback: Transmission Operator and Balancing Authorities develop operating plans to mitigate emergencies. The Reliability Coordinator reviews the plan.

Answer 300

Capacity and Energy Emergencies Feedback: The responsibility of the Balancing Authority is to meet load with sufficient generating resources for normal operations or in the event a generator trips, i.e. reserves. If they cannot meet load they are in a Capacity and Energy Emergency.

Answer 301

Increases the risk to power system reliability Feedback: System Operating Limits should not be exceeded. If limits are exceeded the power system is operating in a less reliable state.

Answer 302

Operating instructions Feedback: During emergency conditions, a system operator may need to issue operating instructions. An operating instruction is a command by operating personnel responsible for the Real-time operation of the interconnected BES to change or preserve the state, status, output, or input of an element or facility of the BES.

Answer 303

Establish backup control center to continue to meet functional obligation and operations Feedback: Backup control centers are established to ensure continued reliable operation of a control center becomes inoperable. Evacuating the primary control center and resuming operations at the backup center are considered emergency operations.

Answer 304

Heavy flows to inductive loads are causing voltage drops in excess of 10% Feedback: Load shed is used after other options such as redispatch or reduction in interchange are used.

Answer 305

Capacitors Feedback: Voltage control equipment such as capacitors counteract the effects of inductive loads by producing reactive power and supporting voltage.