areva prc-24 white paper clean

7/31/2019 AREVA PRC-24 White Paper Clean

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AREVA NP White Paper on PRC-24

AREVA acknowledges the need for transient ride through criteria for voltage andfrequency and applauds the NERC Standard Drafting Team for tackling such difficult

subject matter. AREVA has worked to fulfill Grid Code and Transmission System

Operators requirements in other countries where our nuclear power plants are beingoperated and constructed. These include new EPR plants under construction in Finland and

France as well as operating plants in Germany, France and around the world. We also have

personnel with extensive experience in generation related NERC Standards activities. Wewould like to offer to leverage the knowledge gained in these endeavors to support the

NERC standard effort.

Draft NERC Standard PRC-24 proposes the standard ride through criteria forvoltage shown in Figure 1, which shows the proposed standard for the high and low voltage

excursions.

AREVA understands this criteria was developed partly based on a study of the WECCregion (reference WECC paper) and the resulting criteria was based on bounding system

response for all operating areas, including those where wind generating power plant

characteristics are understood to delay voltage recovery once the fault is cleared However,

Proposed Voltage Ride-Through Standard

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

1.4

-1.0 0.0 1.0 2.0 3.0 4.0

Time (seconds)

Voltage(PU)

Pre Fault

Period

No-Trip

Envelope

0.15

Figure 1


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this criterion is not technically feasible for large thermal/nuclear generating plants for the

following reasons.

1. NERC standards appear to see generators as a discreet part of the overall bulk

power system. While this is accurate for small wind powered induction generators,

each large generation plant consists of a generator and a plant auxiliary distributionpower system which must be designed and coordinated with the transmission power

system.

2. In the face of an extended voltage decrease and a very slow voltage recovery, asbeing proposed, the stability of large inertia generators is questionable and has to be

investigated.

3. The assumption of a near to the plant short-circuit failure with a LVRT is not

technically correct. The behavior of the auxiliary systems and especially of largeMV motors inherent in a steam plant is different when there is a short-circuit and

when there is only a voltage drop at the grid connection.

In Order No. 672, FERC has identified 15 points of justification that will be used toanalyze standards that NERC proposes for approval. These criteria ensure the proposed

standard is just, reasonable, not unduly discriminatory or preferential, and in the publicinterest. Two of these include

Proposed standards must be designed to achieve a specified reliability goal

Proposed standards must contain a technically sound method to achieve the goal

AREVA understands the specified reliability goal is identified in the purpose of the

standard, which for PRC-24 is:

Ensure that generators remain connected to the Bulk Electric System during

voltage and frequency excursions within the defined criteria of this standard incoordination with other system protection schemes to support transmission systemtransient stability.

AREVA believes the current criteria for Low Voltage Ride Through as writtenmisses the target for these two points and thus likely will not be approved by FERC.

AREVA also believes the discussion of record on the PRC-24 standard should clearly state

that the superposition of extended off nominal voltage and frequency is not technicallypossible with US equipment design standards and thus not required.

Below, AREVA offers a technical discussion on our concerns with the existing

standard approach and offers an alternative approach for the SDTs consideration.

The Voltage Ride through criteria curves consists of several diverse parts, as described

in the White Paper developed by the Wind Generation Task Force (WGTF) see Figure 2.


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Figure 2.

Voltage Ride Trough Boundaries

1. Normal and Emergency Voltage Conditions Voltage Tolerance Boundaries

The normal voltage boundaries have been specified to be for the steady-state

operating conditions based on the ANSI C84.1-2006 American National Standard forElectric Power Systems and Equipment Voltage Ratings (60Hz)as follows:

a. Normal Conditions: 5% Continuous Durationb. Emergency Conditions: 10% not specified Duration

These Criteria are currently widely used in practice and can be complied with by all

types of new generating plants designed with an in-plant voltage regulation capability.In connection with these criteria, all new equipment, both on the transmission system

and in new generation plants must be chosen in order to be able to operate and

withstand these voltage excursions.

However, many existing power plants were built prior to standards for normal

transmission system voltage operating bands and thus were designed without in-plantvoltage regulation capabilities. In some cases, assuring nuclear plant offsite power


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voltage adequacy requires minimum voltage limits very near nominal system voltage.

For these plants, close coordination between the transmission system operations and the

plant are required to1. Select the main step up transformer and auxiliary transformer taps

settings to optimize the MVAR support available from the plant under grid

conditions expected most of the time. (e.g. When operating on VoltageSchedule as Required by NERC Standard VAR-2).

2. Assure the transmission system is operated to assure that system

voltage near operating nuclear power plants, with the single contingency (plantaccident, trip and application of safety system loads) maximum voltage drop,

will be adequate to support the safety system operation as required by NRC

regulations and new NERC Standard NUC-1.

Thus, requirements for generation to be able to support a wide band of operating

transmission system voltage is, in essence, a requirement to back fit these old plants with

voltage regulation capability. While this might be the best choice in selected situations, it

might be a less cost effective solution in some regions of the interconnection where thereare higher concentrations of generation. This also may run counter to regulations in some

states, where the utilities make these system design decisions during the long term planningprocesses and are required by the states to design the system on a least overall fleet cost

basis. It is important that the transmission operator and the connected generation fleet

cooperate on these issues as now mandated for nuclear plants through NUC-1.

In the course of sighting plants in the US, AREVA has had discussions with some US

transmission operators who interpret these draft standards to require the superposition of an

extended ability to withstand Emergency Voltage Conditions together with Frequency at95%. Imposing these conditions on plant auxiliary systems are contrary to motor

manufacturing standards in NEMA MG-1 which state

Section III MG 1-2006 LARGE MACHINESINDUCTION

MACHINES Part 20, Page 11

20.14 VARIATIONS FROM RATED VOLTAGE AND RATED FREQUENCY

20.14.1 Running

Induction machines shall operate successfully under running conditions at ratedload with a variation in the voltage or the frequency up to the following:

a. Plus or minus 10 percent of rated voltage, with rated frequency

b. Plus or minus 5 percent of rated frequency, with rated voltagec. A combined variation in voltage and frequency of 10 percent (sum of

absolute values) of the rated values, provided the frequency variation does

not exceed plus or minus 5 percent of rated frequency.

Performance within these voltage and frequency variations will not necessarily be

in accordance with the standards established for operation at rated voltage and

frequency.


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AREVA appreciates the basis for Voltage Ride Through Clarification #6 and

encourages the SDT to keep this clarification in the final standard.

AREVA designs our new plant power systems with voltage regulation capability to

support long-term variations in transmission system voltage, but believes that capitoldecisions on when to add plant voltage controls on existing plants should be made on an as

needed basis to facilitate improved MVAR support and not to support an arbitrary criterion.

A requirement to mandate Automatic Tap changers at existing units when transformers arereplaced may be a reasonable long term approach.

2. LVRT Three-Phase Fault Clearing Boundary

This part of the curve addresses the bolted three-phase fault boundary with normal

clearing, as a worst-case scenario for short-circuit fault, after which the generators are

required to remain in service.

The short-circuit fault in the proximity of the power plant will be seen from the point ofview and response of the power plant similar as the short-circuit fault at the grid connection

(switchyard) of the plant. During the time the fault is connected, the generator terminal

voltage lowers, depending on the type and distance of the fault to the plant and thegenerator is able to deliver only a part of the pre-fault active power (MW) to the grid. Since

the Turbine torque is still constant, the generator experiences an acceleration proportional

to output power imbalance. If not cleared within certain time boundaries, which are

individual to every plant, it will lead to the loss of the transient stability.

Consistent with FERC expectations, the proposed standard clearing time is 9 cycles or

150ms. This is the clearing time of the Zone 1 protection in the connected grid and consistsof:

- Relay operation time

- Communication time- Breaker time

The voltage drop for the duration of the fault is proposed to be down to 0% which is

very conservative but acceptable and is consistent with the statement that a near to plantfault will be seen as a fault in the switchyard connecting the plant to the grid.

AREVA believes this is a reasonable basis for the fault clearing time and 150ms shouldbe used for the US standard. The time 150ms is comparable to the clearing time specified

in the German Grid Code from E.ON and is smaller than the requirement from NORDEL

(Nordic Countries Grid Union) which is requiring the generators to withstand 250msclearing time of the fault based on their weak grid conditions.

It does not appear that breaker-failure protection times were taken into account as a part

of the standards effort. This protection is typically set to wait between 0.1 to 0.35


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seconds for the main protection to clear the fault and should be based on the critical

clearing time for the local generator. This criteria is also correspondent with the definition

that the normal design contingencies include among others a permanent three-phase faulton any generator, transmission circuit, transformer or bus section, with normal fault

clearing and with due regard to reclosing facilities [Kundur, 1993]. It would seem that a

complete standard for transients might address the requirement for the transmissionsystem/switchyard equipment owners to set these breaker failure units and updates the

settings as necessary based on the latest stability study results.

Because the required grid protection clearing times needed to assure stability vary, it is

again important for the Generation Owners and the Transmission Owners and Planners to

collaborate on an on going basis to assure the system design is maintained as needed to

assure reliable operation of the bulk power system as additional generation is added as iscurrently projected.

3. LVRT Voltage Recovery Boundary

This is the part of the standard which addresses the system voltage recovery after the

fault is cleared. It is important to keep in mind that, while part 2 of the curve can be seen asquasi-static and be stated uniformly for all plants, the expected voltage recovery will vary

location by location depending on nearby plant characteristics and its real shape can be

determined only by dynamic simulation. For the proposed criteria, the initial condition isthat the voltage is still at 0% and linearly recovers to 90% 1.6 seconds after the fault

clearing. While this criteria is certainly bounding for all types of generation, it is unrealistic

for large generation plants for the reasons stated above.

There is also an important difference between synchronous (mostly used in thermal,

nuclear and hydro generating power plants) and asynchronous (wind generating plants)

generators that requires the stator of the asynchronous generator to be magnetized from thegrid before it works and therefore needs reactive power in order to build up the magnetic

field.

The asynchronous generator is able to operate also in a stand alone system, if it is

provided with capacitors which supply the necessary magnetization current. It is also

required that there is some remnant magnetization in the rotor iron, i.e. some leftover

magnetism during the start of the turbine. Otherwise there is a need for a battery and powerelectronics, or a small diesel generator to start the system). This means that after voltage

drops in the supplying grid the asynchronous generator needs relative longer time for

supporting the voltage recovery, because it needs the extra time to rebuild itselectromagnetic field compared to the synchronous generator.

Synchronous generators are equipped with AVR systems which provide a fault forcingfunction to help the transmission system recover from faults. With these generators

nearby, the system voltage will recover quickly to >90% once the fault is cleared at

150msec.


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In this part after the fault was cleared, the leading magnet wheel of the synchronous

generator will be slowed down by the recurrent electrical torque and reaches in the stable

state under declining oscillations the synchronous rpm based on the grid frequency (60Hz).The proposed standard attempts to describe this dynamic behavior trough the linearly

increasing part of the curve.

If the synchronizing capability of the grid not sufficient to slow down the accelerated

magnet wheel after the fault was cleared, the turbo-generator set will transit into slip mode

operation, which is associated with enormous mechanical stress. This is in fact the loss ofthe transient stability. Areva believes the standard should consider this and use a criteria

based on ensuring the generator will not reach this undesired operating condition.

Other parameters influence the after fault voltage recovery at the grid connection:

oThe inertia of the turbo-generating set (higher inertia means higher stability)

oThe position of the generator voltage regulator and the resulting operation

mode either leading, lagging or cos=1 (measure for the level of stability of the

generator prior to the fault=> leading =>max angular displacement =>worst-case)

oThe grid connection voltage level and the related short-circuit current

capacity (it is the measure for the resynchronization capability of the grid)

The purpose for this introduction is to show how complicated correlations are in an

attempt to represent the entire transmission system by a simple curve of the standard.

According to the WGTF white paper, the voltage points during voltage recovery for

Zone 2 three-phase fault with normal clearing time have been drawn into the diagram and acurve was chosen to begin at 0% voltage and 150ms to reach the 90% voltage in a manner

that ensures all the voltage points will be within the area specified/marked-off by the curve(Figure 3).

Note that only handful (12) of the voltage points were available for this study which

makes it less reliable in terms of statistical evaluation and is unlikely that all possible

scenarios are covered. This criteria forces large plants connected to grids with high voltageand higher short-circuit capability (in the Fig.3 represented by the points Nine Mile 230kV

(PAC) and Foote Creek 230kV (PAC)) to assure they can ride trough very poor voltage

conditions that can not realistically occur on their grid connections.


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Figure 3

Existing and new LVTR standard for WECC with Zone 2 Relay Results added

Fig.4 shows a comparison of the proposed standard LVRT vs. a generator stability

study from a 1300MW unit which clearly shows how far the proposed boundary and the

voltage recovery for the generator terminals after 150ms short-circuit fault differ. In the

study the voltage recovery up to 100% is achieved after 900ms versus the by standardproposed 1.6s.


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Figure 4

Proposed LVTR standard for WECC vs. 1300MW unit stability study.

The proposed criteria may be acceptable for the generators if they can maintain

stability, but likely will cause problems for the auxiliary systems of the thermal and nuclearplants, because of the impact on the voltage in the auxiliary systems. The voltage drop will

be propagated through the whole system and the relative slow recovery can cause under-

voltage trips for vital consumers which will lead to a plant trip even if the generatorremains stable. Even newer plants equipped with On Line Tap Changers can not workagainst the voltage drop, because the whole event is too fast for the OLTC to react.

AREVA has extensively studied the ability of in-plant power systems to ride throughgrid initiated voltage transients resulting from the near to plant short-circuit failures.

Several slides based on these studies are included in the Fig 5 and 6.


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Figure 5

Figure 5 shows the voltage recovery profiles at the MV system distributions within

the auxiliary systems of a plant after the clearing of the near-to-plant short-circuit

failures, cleared after 150ms and 210ms. These curves are very similar to the voltagerecovery profile on the main generator terminals and clearly show the impact of theshort-circuit failure to the whole auxiliary system.

This impact is caused by the ratio of the impedances of the equipment which aredecisively involved in the Short-Circuit Impedance such as the Step-Up (ZStT),

Auxiliary Transformer (ZAUX) and the MV-Motors (ZMot), and determine the resulting

short-circuit current in the system.


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Figure 6

In the Figure 6 you can observe the behavior of a MV-Motor during and after a

short-circuit. In the first 200ms to 300ms, the motor Short-Circuit Current contribution

decreases almost to zero. This means that the motor has spent the storedelectromagnetic field and will be stalled or tripped by the associated undervoltage

monitoring (this case is not shown in the Figure 6). The Short-Circuit Failure is cleared

after 300ms and after this period a re-acceleration of the stalled/tripped motors occurs.Clearly observed can be the Motor Starting Current which is 3,8 times the Motor rated

current and also the voltage recovery.

The technical limit for the time plant bus voltage can be depressed due to external

faults is based on time constants for the decay of the electromagnetic field in plant

motors, which will support plant voltage until the magnetic fields collapse. The limit is

~ 200mSec and thus, the clearing time of 150mSec is appropriate from this perspective.

As a conclusion we would like to state, that the proposed approach is not feasible

for thermal and nuclear power plants and that a meaningful standard to address thestated reliability goal must not only consider the main generator unit protection settings

and the turbo generator set stability but also the whole auxiliary system of the plant.

Due to technology differences, developing criteria for all plants based a study focusingon wind generating plants seems inappropriate.


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AREVA suggests that in order to ensure that the all plants can ride through

disturbances such as a short-circuit in the grid, stability studies are needed (and already

required to be performed by TPL standards) to document the expected voltagerecovery, which should be provided to the generation owners. Generation owners

should then be required to have documented studies to show all plant equipment can

withstand this transient or to identify any limitations. These studies should also showthat plant relaying should be coordinated with the simulation of a short-circuit fault in

the plant switchyard which will be cleared within 150ms and show that the generator

remains stable. Note that loads that may cause a plant trip due to a low voltage mightrequire a dynamic analyses to asses the ability to survive the transient. Suggested

standard language is included in attachment 1.

4. HVRT High Voltage Boundary

This section addresses the high voltage ride trough which covers the high voltage

period after the fault was cleared.

A concern would be that the specified voltage level in the first (120%) second(118%) and third (115%) step of the HVRT will be propagated trough the whole

auxiliary system of thermal and nuclear power plants and could lead to over voltage on

the consumers. The NEMA MG 1-2006 standard is stating for AC Motors that theyshould be able to operate at plus/minus 10% of the rated voltage at rated load under

running conditions but there is no guidance for such a very short-term voltage

variations (1s duration) as described in the HVRT curve.

For example the Nordic Grid Code is specifying 110% voltage level as the

maximum for short-term overvoltage (up to 1h duration) with a small power output

decrease allowable (up to 10%). The document European utility Requirements forLWR Nuclear Power Plants specifies the short-term overvoltage with max 107.5% for

maximum 30min.

The impact of such fast voltage swells on plant power systems should be investigated

prior to making a standard HVRT.

5. References:

a. The Technical Basis for the new WECC Voltage Ride-Trough (VTR)

Standard, June 13 2007, Developed by Wind Generation Task Force

(WGTF)b. Power System Stability and Control, 1993, Kundur

c. Nordic Grid Code 2007, NORDEL

d. Grid Code (High and Extra High Voltage), 1. August 2003, E-ON/Netze. European utility Requirements for LWR Nuclear Power Plants Rev C,

April/2001, EUR

f. NEMA Standard MG 1-2006


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6. Lack of Design Guidance in US Standards

AREVA is not aware of any guidance in US generation plant design standards thataddress these issues, hence many new plants may be built that do not address these

issues. NERC should engage IEEE to develop design standards to be applied to the next

generation of plants.

7. AREVA Recommendations for Voltage Ride-Trough

NERC Reliability Standards Development Procedure allows for the development of a

white paper, defined as

An informal paper stating a position or concept. A white paper may be used topropose preliminary concepts for a standard or one of the documents above.

AREVA is not aware of a white paper considering characteristics for all types of

generation for this issue and would support the development of one. AREVA suggests onthe following approach for the voltage ride through standard to fully address the technical

issues associated with voltage ride through.


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A. Introduction

1. Title: Generator Performance During Frequency and

Voltage Excursions

2. Number: PRC-024-2

3. Purpose: Ensure that generators remain connected to

the Bulk Electric System during voltage and frequency excursions

within the defined criteria of this standard in coordination with other

system protection schemes to support transmission system transient

stability.

4. Applicability4.1. Generator Owner

4.2. Transmission Planners

4.3. Transmission System Owners

B. Requirements

R1. Generator Owners shall document studies to confirm each

set generatorion plant protective relaying to meet the

following performance requirements for generator units20 MVA and greater, or generating plants/ facilities

consisting of one or more units with total generation > 75

MVA (gross aggregate nameplate rating) at the point of

interconnection to the Bulk Electric System to remain

connected during steady-state and system frequency

excursions as follows:

R1.1. Operate continuously within a frequency range of

59.5 Hz to 60.5 Hz.

R1.2. Generators shall remain connected during

frequency excursions in accordance with

Attachment 1of -PRC-024-2.


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R1.3. Instantaneous underfrequency relay trips setting

shall be set no higher than 57.8 Hz.

R1.4. Instantaneous overfrequency relay trip settings shall

be set no lower than 61.2 Hz.

R1.5. The Generator Owner shall provide to Regional

Entities, Reliability Coordinators and Transmission

Operators generator protection frequency trip

settings as specified by requirements R1.1 through

R1.4 within 30 days of any change or request for

data, to coordinate with regional Off Nominal

Frequency Load Shedding and Restoration

programs.

R2. The transmission planner shall

R2.1. Develop and communicate results of stability

studies required by the TPL standards to determine

critical clearing time and subsequent post fault

voltage recovery transient expected at the

switchyard based on worst case conditions (unit at

full power and worst case reactive power output).

R2.2. Use any design limitations identified by thegeneration owner per in their transmission models

used to perform studies

R3. The owner of the switchyard and the transmission lines

coming to the plant switchyard shall use the calculated

critical clearing time to set breaker and breaker failure

protective relaying timing to assure all faults will be

cleared prior to the unit reaching an unstable state.

R4. Generator Owners shall document studies to confirm the

generator protective relaying to can meet the following

performance requirements for generator units 20 MVA

and greater, or generating plants/facilities consisting of

one or more units with total generation > 75 MVA (gross


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aggregate nameplate rating) at the point of

interconnection to the Bulk Electric System to will remain

connected during steady-state and system voltage

excursions as follows:

R4.1. Operate continuously within 95% to 105% of rated

generator terminal voltage with transformer taps

selected to optimize the level of MVAR support

available with switchyard voltage on schedule as

defined per the VAR-1 standard.

R4.2. Operate on the site specific switchyard voltage

schedule per VAR-1 and identify any limitations to

the normal transmission system voltage bands due

to plant design issues (such as those covered by

NUC-1).

R4.3. Generators will remain connected during transient

voltage excursions measured at the point of

interconnection to the Bulk Electric System in

accordance with the plant specific voltage recovery

curves as determined by periodic transmission

system stability studies. No other plant trips should

occur due to the limiting voltage recovery transient.

R4.3.1. Plant undervoltage relaying shall be

designed to coordinate with the worst case

voltage recovery for which the plant will be

stable.

R4.3.2. If there are plant design issues that require a

trip during the defined voltage recover

period, the Generation owner shallcommunicate these limitations to the

transmission planner.

R4.3.3. Generators are permitted to be tripped after

fault initiation if this action is intended as


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part of a special protection scheme (SPS) or

remedial action scheme (RAS).

R4.3.4. Generators are permitted to be tripped when

clearing a system fault necessitates

disconnecting the generator.

R4.4. The Generator Owner shall provide to Regional

Entities, Planning Coordinators, Transmission

Operators and Transmission Planners generator

protection trip settings that are affected by

voltagethe study as specified by requirement

R2.2R4 within 30 days of any change or request for

data.

R5. Existing generators (at the time of regulatory approval of

this standard) that are unable to comply with any of the

following requirements, R1 and sub requirements R1.1

through R1.4, R2 and sub requirements R2.1 through

R2.2, due to equipment limitations shall notify the

Regional Entity and provide documentation that explains

the technical limitation and prepare a mitigation plan for

such equipment limitations.

C. Measures

M1. Generator Owners demonstrate compliance by having

documentation that generator protective relays have

been set in accordance with the requirements in R41.

M2. The transmission planners shall demonstrate

compliance by showing results of studies and showing

proof that the results were provided to the Generation

Owner as required by R2.M3. The transmission/switchyard equipment owners shall

demonstrate compliance by showing that Breaker

Failure protection time settings were set based on the

local units CCTs.


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documentation that generator protective relays have

been set in accordance with the requirements in R2.


documentation and a mitigation plan for any

generator/plant that do not comply due to equipment

limitations in accordance with R3.

D. Regional Differences

D1. Reference Documents

The Technical Justification for the New WECC Voltage Ride-Through (VRT)

Standard, A White Paper Developed by the Wind Generation Task Force (WGTF),

dated June 13, 2007, a guideline approved by WECC Technical Studies Subcommittee.


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Attachment 1-PRC-024-2

PROPOSED OFF NOMINAL FREQUENCY CAPABILITY CURVE

55

56

57

58

59

60

61

62

63

64

65

0.01 0.1 1 10 100 1000 10000

TIME (sec)

FRE

QUENCY(Hz)

Frequency (hertz) 61.2 60.5 59.5 57.8

Time (seconds) .0095 to 2 600 to 10,000 1800 to10,000

.0095 to 2

No Trip

Zone


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Attachment 2-PRC-024-2

Proposed Example of a Voltage Ride-Through Curve

Voltage Ride-Through Curve Clarifications

1. This curve is based upon normal operating voltages as

measured at the point of interconnection to the Bulk ElectricSystem.

2. Generator protection relays monitor low side voltage. If the

main generator step transformer tap is set for other than 1.0

per unit, then the generator protection relay settings must

account for this.

3. This voltage standard may be met by installing additional

equipment (such as dynamic VAR compensation) within the

generating facility.

4. When applying the above curve to three-phase Zone 1 faults

with normal clearing, utilize actual fault clearing times, but not

greater than 9 cycles.


0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

1.4

-1.0 0.0 1.0 2.0 3.0 4.0

Time (seconds)

Voltage(PU)

Pre Fault

Period

No-Trip

Envelope

0.15


0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

1.4

-1.0 0.0 1.0 2.0 3.0 4.0

Time (seconds)

Voltage(PU)

Pre Fault

Period

No-Trip

Envelope

0.15


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5. Within the voltage ride-through standard fault recovery and

high voltage boundaries, referred to as the No Trip Envelope

in the above curve generators are required to remain in-service

after fault clearing.

6. The curve depicted in this Attachment 2 assumes system

frequency of 60 Hertz.