PRC-024-1 Rel Standard

PRC-024-1 Rel Standard.pdf

FERC-725G (Final Rule in RM13-16-000) Mandatory Reliability Standards for the Bulk-Power System: PRC Standards

PRC-024-1 Rel Standard

OMB: 1902-0252

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S ta n d a rd P RC-024-1 — Ge n e rato r Fre q u e n cy a n d Vo lta g e P ro te ctive Re la y S e ttin g s
A. Introduction
1.

Title:

Generator Frequency and Voltage Protective Relay Settings

Number:

PRC-024-1

Purpose: Ensure Generator Owners set their generator protective relays such that
generating units remain connected during defined frequency and voltage excursions.

Applicability:
4.1. Generator Owner

Effective Date:
5.1. In those jurisdictions where regulatory approval is required:

5.1.1

By the first day of the first calendar quarter, two calendar years following
applicable regulatory approval, or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities, each Generator
Owner shall have verified at least 40 percent of its Facilities are fully
compliant with Requirements R1, R2, R3, and R4.

5.1.2

By the first day of the first calendar quarter, three calendar years following
applicable regulatory approval, or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities, each Generator
Owner shall have verified at least 60 percent of its Facilities are fully
compliant with Requirements R1, R2, R3, and R4.

5.1.3

By the first day of the first calendar quarter, four calendar years following
applicable regulatory approval, or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities, each Generator
Owner shall have verified at least 80 percent of its Facilities are fully
compliant with Requirements R1, R2, R3, and R4.

5.1.4

By the first day of the first calendar quarter, five calendar years following
applicable regulatory approval, or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities, each Generator
Owner shall have verified 100 percent of its Facilities are fully compliant
with Requirements R1, R2, R3, and R4.

5.2. In those jurisdictions where regulatory approval is not required:

5.2.1

By the first day of the first calendar quarter, two calendar years following
Board of Trustees approval, each Generator Owner shall have verified at
least 40 percent of its Facilities are fully compliant with Requirements R1,
R2, R3, and R4.

5.2.2

By the first day of the first calendar quarter, three calendar years following
Board of Trustees approval, each Generator Owner shall have verified at
least 60 percent of its Facilities are fully compliant with Requirements R1,
R2, R3, and R4.

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5.2.3

By the first day of the first calendar quarter, four calendar years following
Board of Trustees approval, each Generator Owner shall have verified at
least 80 percent of its Facilities are fully compliant with Requirements R1,
R2, R3, and R4.

5.2.4

By the first day of the first calendar quarter, five calendar years following
Board of Trustees approval, each Generator Owner shall have verified 100
percent of its Facilities are fully compliant with Requirements R1, R2, R3,
and R4.

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B. Requirements
R1.

R2.

Each Generator Owner that has generator frequency protective relaying 1 activated to trip
its applicable generating unit(s) shall set its protective relaying such that the generator
frequency protective relaying does not trip the applicable generating unit(s) within the
“no trip zone” of PRC-024 Attachment 1, subject to the following exceptions: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]
•

Generating unit(s) may trip if the protective functions (such as out-of-step functions
or loss-of-field functions) operate due to an impending or actual loss of synchronism
or, for asynchronous generating units, due to instability in power conversion control
equipment.

•

Generating unit(s) may trip if clearing a system fault necessitates disconnecting (a)
generating unit(s).

•

Generating unit(s) may trip within a portion of the “no trip zone” of PRC-024
Attachment 1 for documented and communicated regulatory or equipment
limitations in accordance with Requirement R3.

Each Generator Owner that has generator voltage protective relaying1 activated to trip its
applicable generating unit(s) shall set its protective relaying such that the generator
voltage protective relaying does not trip the applicable generating unit(s) as a result of a
voltage excursion (at the point of interconnection 2) caused by an event on the
transmission system external to the generating plant that remains within the “no trip
zone” of PRC-024 Attachment 2. If the Transmission Planner allows less stringent
voltage relay settings than those required to meet PRC-024 Attachment 2, then the
Generator Owner shall set its protective relaying within the voltage recovery
characteristics of a location-specific Transmission Planner’s study. Requirement R2 is
subject to the following exceptions: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
•

Generating unit(s) may trip in accordance with a Special Protection System (SPS) or
Remedial Action Scheme (RAS).

•

Generating unit(s) may trip if clearing a system fault necessitates disconnecting (a)
generating unit(s).

•

Generating unit(s) may trip by action of protective functions (such as out-of-step
functions or loss-of-field functions) that operate due to an impending or actual loss
of synchronism or, for asynchronous generating units, due to instability in power
conversion control equipment.

Each Generator Owner is not required to have frequency or voltage protective relaying (including but not limited to
frequency and voltage protective functions for discrete relays, volts per hertz relays evaluated at nominal frequency,
multi-function protective devices or protective functions within control systems that directly trip or provide tripping
signals to the generator based on frequency or voltage inputs) installed or activated on its unit.
2

For the purposes of this standard, point of interconnection means the transmission (high voltage) side of the generator
step-up or collector transformer.

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•

R3.

Generating unit(s) may trip within a portion of the “no trip zone” of PRC-024
Attachment 2 for documented and communicated regulatory or equipment
limitations in accordance with Requirement R3.

Each Generator Owner shall document each known regulatory or equipment limitation 3
that prevents an applicable generating unit with generator frequency or voltage protective
relays from meeting the relay setting criteria in Requirements R1 or R2 including (but not
limited to) study results, experience from an actual event, or manufacturer’s advice.
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
3.1. The Generator Owner shall communicate the documented regulatory or equipment

limitation, or the removal of a previously documented regulatory or equipment
limitation, to its Planning Coordinator and Transmission Planner within 30 calendar
days of any of the following:

R4.

•

Identification of a regulatory or equipment limitation.

•

Repair of the equipment causing the limitation that removes the limitation.

•

Replacement of the equipment causing the limitation with equipment that
removes the limitation.

•

Creation or adjustment of an equipment limitation caused by consumption of the
cumulative turbine life-time frequency excursion allowance.

Each Generator Owner shall provide its applicable generator protection trip settings
associated with Requirements R1 and R2 to the Planning Coordinator or Transmission
Planner that models the associated unit within 60 calendar days of receipt of a written
request for the data and within 60 calendar days of any change to those previously
requested trip settings unless directed by the requesting Planning Coordinator or
Transmission Planner that the reporting of relay setting changes is not required.
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

C. Measures
M1. Each Generator Owner shall have evidence that generator frequency protective relays

have been set in accordance with Requirement R1 such as dated setting sheets, calibration
sheets or other documentation.
M2. Each Generator Owner shall have evidence that generator voltage protective relays have

been set in accordance with Requirement R2 such as dated setting sheets, voltage-time
curves, calibration sheets, coordination plots, dynamic simulation studies or other
documentation.
M3. Each Generator Owner shall have evidence that it has documented and communicated any

known regulatory or equipment limitations (excluding limitations noted in footnote 3)
that resulted in an exception to Requirements R1 or R2 in accordance with Requirement
3

Excludes limitations that are caused by the setting capability of the generator frequency and voltage protective relays
themselves but does not exclude limitations originating in the equipment that they protect.

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R3 such as a dated email or letter that contains such documentation as study results,
experience from an actual event, or manufacturer’s advice.
M4. Each Generator Owner shall have evidence that it communicated applicable generator

protective relay trip settings in accordance with Requirement R4, such as dated e-mails,
correspondence or other evidence and copies of any requests it has received for that
information.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority

The Regional Entity shall serve as the Compliance Enforcement Authority (CEA)
unless the applicable entity is owned, operated, or controlled by the Regional Entity.
In such cases, the ERO or a Regional Entity approved by FERC or other applicable
governmental authority shall serve as the CEA.
1.2. Data Retention

The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances where
the evidence retention period specified below is shorter than the time since the last
audit, the Compliance Enforcement Authority may ask an entity to provide other
evidence to show that it was compliant for the full time period since the last audit.
The Generator Owner shall retain evidence of compliance with Requirement R1
through R4; for 3 years or until the next audit, whichever is longer.
If a Generator Owner is found non-compliant, the Generator Owner shall keep
information related to the non-compliance until mitigation is complete and approved
for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes

Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information

None

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Violation Severity Levels
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

N/A

The Generator Owner
that has frequency
protection activated to
trip a generating unit,
failed to set its
generator frequency
protective relaying so
that it does not trip
within the criteria
listed in Requirement
R1 unless there is a
documented and
communicated
regulatory or
equipment limitation
per Requirement R3.

N/A

The Generator Owner
with voltage protective
relaying activated to
trip a generating unit,
failed to set its voltage
protective relaying so
that it does not trip as a
result of a voltage
excursion at the point
of interconnection,
caused by an event
external to the plant
per the criteria
specified in
Requirement R2 unless
there is a documented
and communicated
regulatory or
equipment limitation
per Requirement R3.

The Generator Owner
documented the
known non-protection
system equipment
limitation that
prevented it from
meeting the criteria in
Requirement R1 or R2
and communicated the
documented limitation
to its Planning
Coordinator and
Transmission Planner

The Generator Owner
failed to document any
known non-protection
system equipment
limitation that
prevented it from
meeting the criteria in
Requirement R1 or R2.

OR
The Generator Owner
failed to communicate

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Lower VSL

Moderate VSL

High VSL

more than 30 calendar
days but less than or
equal to 60 calendar
days of identifying the
limitation.

more than 60 calendar
days but less than or
equal to 90 calendar
days of identifying the
limitation.

more than 90 calendar
days but less than or
equal to 120 calendar
days of identifying the
limitation.

the documented
limitation to its
Planning Coordinator
and Transmission
Planner within 120
calendar days of
identifying the
limitation.

The Generator Owner
provided its generator
protection trip settings
more than 60 calendar
days but less than or
equal to 90 calendar
days of any change to
those trip settings.

The Generator Owner
provided its generator
protection trip settings
more than 90 calendar
days but less than or
equal to 120 calendar
days of any change to
those trip settings.

The Generator Owner
provided its generator
protection trip settings
more than 120
calendar days but less
than or equal to 150
calendar days of any
change to those trip
settings.

The Generator Owner
failed to provide its
generator protection
trip settings within 150
calendar days of any
change to those trip
settings.

OR
The Generator Owner
provided trip settings
more than 60 calendar
days but less than or
equal to 90 calendar
days of a written
request.

Severe VSL

OR
OR
The Generator Owner
provided trip settings
more than 90 calendar
days but less than or
equal to 120 calendar
days of a written
request.

OR
The Generator Owner
provided trip settings
more than 120
calendar days but less
than or equal to 150
calendar days of a
written request.

The Generator Owner
failed to provide trip
settings within 150
calendar days of a
written request.

E. Regional Variances
None
F. Associated Documents
None

Version History
Version

Date

Action

May 9, 2013

Adopted by the NERC Board of
Trustees

Change Tracking

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G. References
1.

“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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PRC-024 — Attachment 1

OFF NOMINAL FREQUENCY CAPABILITY CURVE
68
Quebec
66
64

No Trip Zone
(not including the
lines)

Frequency (Hz)

ERCOT

Western

Eastern

60
ERCOT

Eastern Interconnection

58
Western
56

Quebec

0.1

100
Time (sec)

54
10000

1000

Curve Data Points:
Eastern Interconnection
High Frequency Duration

Low Frequency Duration

Frequency (Hz)

Time (Sec)

Frequency (Hz)

Time (sec)

≥61.8

Instantaneous trip

≤57.8

Instantaneous trip

≥60.5
<60.5

(90.935-1.45713*f)

Continuous operation

≤59.5
> 59.5

(1.7373*f-100.116)

Continuous operation

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Western Interconnection
High Frequency Duration

Low Frequency Duration

Frequency (Hz)

Time (Sec)

Frequency (Hz)

Time (sec)

≥61.7

Instantaneous trip

≤57.0

Instantaneous trip

≥61.6

≤57.3

0.75

≥60.6

180

≤57.8

7.5

<60.6

Continuous operation

≤58.4

≤59.4

180

>59.4

Continuous operation

Quebec Interconnection
High Frequency Duration

Low Frequency Duration

Frequency (Hz)

Time (Sec)

Frequency (Hz)

Time (Sec)

>66.0

Instantaneous trip

<55.5

Instantaneous trip

≥63.0

≤56.5

0.35

≥61.5

≤57.0

≥60.6

660

≤57.5

<60.6

Continuous operation

≤58.5

≤59.4

660

>59.4

Continuous operation

ERCOT Interconnection
High Frequency Duration

Low Frequency Duration

Frequency (Hz)

Time (Sec)

Frequency (Hz)

Time (sec)

≥61.8

Instantaneous trip

≤57.5

Instantaneous trip

≥61.6

≤58.0

≥60.6

540

≤58.4

<60.6

Continuous operation

≤59.4

540

>59.4

Continuous operation

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Voltage Ride-Through
Time Duration Curve

1.30
1.25
1.20
1.15
1.10
1.05
1.00
0.95
0.90
0.85
0.80
0.75
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00

No Trip Zone

0.5

1.5

2.5

3.5

POI Voltage (per unit)

PRC-024— Attachment 2

Time (sec)
High Voltage Duration

Low Voltage Duration

Ride Through Duration:
High Voltage Ride Through Duration

Low Voltage Ride Through Duration

Voltage (pu)

Time (sec)

Voltage (pu)

Time (sec)

≥1.200

Instantaneous trip

<0.45

0.15

≥1.175

0.20

<0.65

0.30

≥1.15

0.50

<0.75

2.00

≥1.10

1.00

<0.90

3.00

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Voltage Ride-Through Curve Clarifications
Curve Details:
1. The per unit voltage base for these curves is the nominal operating voltage specified by the
Transmission Planner in the analysis of the reliability of the Interconnected Transmission
Systems at the point of interconnection to the Bulk Electric System (BES).
2. The curves depicted were derived based on three-phase transmission system zone 1 faults
with Normal Clearing not exceeding 9 cycles. The curves apply to voltage excursions
regardless of the type of initiating event.
3. The envelope within the curves represents the cumulative voltage duration at the point of
interconnection with the BES. For example, if the voltage first exceeds 1.15 pu at 0.3
seconds after a fault, does not exceed 1.2 pu voltage, and returns below 1.15 pu at 0.4
seconds, then the cumulative time the voltage is above 1.15 pu voltage is 0.1 seconds and is
within the no trip zone of the curve.
4. The curves depicted assume system frequency is 60 Hertz. When evaluating Volts/Hertz
protection, you may adjust the magnitude of the high voltage curve in proportion to
deviations of frequency below 60 Hz.
5. Voltages in the curve assume minimum fundamental frequency phase-to-ground or phaseto-phase voltage for the low voltage duration curve and the greater of maximum RMS or
crest phase-to-phase voltage for the high voltage duration curve.
Evaluating Protective Relay Settings:
1. Use either the following assumptions or loading conditions that are believed to be the most
probable for the unit under study to evaluate voltage protection relay setting calculations on
the static case for steady state initial conditions:
a. All of the units connected to the same transformer are online and operating.
b. All of the units are at full nameplate real-power output.
c. Power factor is 0.95 lagging (i.e. supplying reactive power to the system) as
measured at the generator terminals.
d. The automatic voltage regulator is in automatic voltage control mode.
2. Evaluate voltage protection relay settings assuming that additional installed generating plant
reactive support equipment (such as static VAr compensators, synchronous condensers, or
capacitors) is available and operating normally.
3. Evaluate voltage protection relay settings accounting for the actual tap settings of
transformers between the generator terminals and the point of interconnection.

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* FOR INFORMATIONAL PURPOSES ONLY *
Enforcement Dates: Standard PRC-024-1 — Generator Frequency and Voltage Protective Relay
Settings
United States
Standard

Requirement

PRC-024-1

All

Enforcement Date

Inactive Date

This standard has not yet been approved by the applicable regulatory authority.

Printed On: August 23, 2013, 08:07 AM

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