Proposed Standard PRC-025-1, submitted 9/30/2013

proposedPRC-025-1_20130930-5277.pdf

FERC-725G (Final Rule in RM13-19 & RM14-3) Mandatory Reliability Standards for the Bulk-Power System: PRC Standards

Proposed Standard PRC-025-1, submitted 9/30/2013

OMB: 1902-0252

⚠️ Notice: This form may be outdated. More recent filings and information on OMB 1902-0252 can be found here:

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PRC-025-1— Generator Relay Loadability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. The Standards Committee approved the SAR for posting on August 12, 2010.
2. SAR was posted for formal comment on August 19, 2010.
3. SAR was revised to add one directive from paragraph P. 224 relating to Phase I on
November 1, 2010.
4. SC authorized moving the SAR (Phase II – Generator Relay Loadability) forward to
standard development on March 20, 2012.
5. Draft 1 of the standard was posted for a 30-day formal comment period from October 5,
2012 to November 5, 2012.
6. Draft 2 of the standard was posted for a 45-day formal comment period from January 25,
2013 to March 11, 2013 and an initial ballot in the last ten days of the comment period.
7. Draft 3 of the standard was posted for a 30-day formal comment period from April 25,
2013 to May 24, 2013 and a successive ballot in the last ten days of the comment period.
8. Draft 4 of the standard was posted for a 30-day formal comment period from June 20 to
July 19, 2013 and a successive ballot in the last ten days of the comment period.
9. Draft 5 of the standard was posted for a 10-day recirculation ballot from August 2 to
August 12, 2013.
Description of Current Draft
The Generator Relay Loadability Standard Drafting Team (GENRLOSDT) is posting Draft 5 of
PRC-025-1, Generator Relay Loadability for a 10-day recirculation.
Anticipated Actions

Anticipated Date

30-day Formal Comment Period

October 2012

45-day Formal Comment Period and Initial Ballot

January 2013

30-day Formal Comment Period and Successive Ballot

May 2013

30-day Formal Comment Period and Successive Ballot

June 2013

Recirculation ballot

July 2013

BOT adoption

August 2013

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PRC-025-1— Generator Relay Loadability

File with FERC

September 30, 2013
(regulatory directive)

Effective Dates
See PRC-025-1 Implementation Plan.
Version History
Version
1.0

Date
TBD

Action
Effective Date

Change
Tracking
New

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
No new or revised term is being proposed.

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PRC-025-1— Generator Relay Loadability

When this standard has received ballot approval, the text boxes will be moved to the Application
Guidelines Section of the Standard.
A. Introduction
1.

Title:

Generator Relay Loadability

Number:

PRC-025-1

Purpose: To set load-responsive protective relays associated with generation
Facilities at a level to prevent unnecessary tripping of generators during a system
disturbance for conditions that do not pose a risk of damage to the associated
equipment.
3.

Applicability:
3.1. Functional Entities:

3.1.1

Generator Owner that applies load-responsive protective relays at the
terminals of the Elements listed in 3.2, Facilities.

3.1.2

Transmission Owner that applies load-responsive protective relays at the
terminals of the Elements listed in 3.2, Facilities.

3.1.3

Distribution Provider that applies load-responsive protective relays at the
terminals of the Elements listed in 3.2, Facilities.

3.2. Facilities: The following Elements associated with Bulk Electric System (BES)

generating units and generating plants, including those generating units and
generating plants identified as Blackstart Resources in the Transmission
Operator’s system restoration plan:
3.2.1

Generating unit(s).

3.2.2

Generator step-up (i.e., GSU) transformer(s).

3.2.3

Unit auxiliary transformer(s) (UAT) that supply overall auxiliary power
necessary to keep generating unit(s) online.1

3.2.4

Elements that connect the GSU transformer(s) to the Transmission system
that are used exclusively to export energy directly from a BES generating
unit or generating plant. Elements may also supply generating plant loads.

3.2.5

Elements utilized in the aggregation of dispersed power producing
resources.

These transformers are variably referred to as station power, unit auxiliary transformer(s) (UAT), or station service
transformer(s) used to provide overall auxiliary power to the generator station when the generator is running. Loss
of these transformers will result in removing the generator from service. Refer to the PRC-025-1 Guidelines and
Technical Basis for more detailed information concerning unit auxiliary transformers.
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PRC-025-1— Generator Relay Loadability
4.

Background:
After analysis of many of the major disturbances in the last 25 years on the North
American interconnected power system, generators have been found to have tripped for
conditions that did not apparently pose a direct risk to those generators and associated
equipment within the time period where the tripping occurred. This tripping has often
been determined to have expanded the scope and/or extended the duration of that
disturbance. This was noted to be a serious issue in the August 2003 “blackout” in the
northeastern North American continent.2
During the recoverable phase of a disturbance, the disturbance may exhibit a “voltage
disturbance” behavior pattern, where system voltage may be widely depressed and may
fluctuate. In order to support the system during this transient phase of a disturbance,
this standard establishes criteria for setting load-responsive protective relays such that
individual generators may provide Reactive Power within their dynamic capability
during transient time periods to help the system recover from the voltage disturbance.
The premature or unnecessary tripping of generators resulting in the removal of
dynamic Reactive Power exacerbates the severity of the voltage disturbance, and as a
result changes the character of the system disturbance. In addition, the loss of Real
Power could initiate or exacerbate a frequency disturbance.

Effective Date: See Implementation Plan

B. Requirements and Measures
R1. Each Generator Owner,

Transmission Owner, and
Distribution Provider shall
apply settings that are in
accordance with PRC-025-1 –
Attachment 1: Relay Settings,
on each load-responsive
protective relay while
maintaining reliable fault
protection. [Violation Risk
Factor: High] [Time Horizon:
Long-Term Planning]
M1. For each load-responsive

protective relay, each
Generator Owner,
Transmission Owner, and
Distribution Provider shall
have evidence (e.g.,
summaries of calculations,

Rationale for R1:
Requirement R1 is a risk-based requirement that
requires the responsible entity to be aware of each
protective relay subject to the standard and applies
an appropriate setting based on its calculations or
simulation for the conditions established in
Attachment 1.
The criteria established in Attachment 1 represent
short-duration conditions during which generation
Facilities are capable of providing system reactive
resources, and for which generation Facilities have
been historically recorded to disconnect, causing
events to become more severe.
The term, “while maintaining reliable fault
protection” in Requirement R1 describes that the
responsible entity is to comply with this standard
while achieving their desired protection goals.
Refer to the Guidelines and Technical Basis,
Introduction, for more information.

Interim Report: Causes of the August 14th Blackout in the United States and Canada, U.S.-Canada Power System
Outage Task Force, November 2003 (http://www.nerc.com/docs/docs/blackout/814BlackoutReport.pdf)
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PRC-025-1— Generator Relay Loadability

spreadsheets, simulation reports, or setting sheets) that settings were applied in
accordance with PRC-025-1 – Attachment 1: Relay Settings.
C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence 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 (CEA) 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, Transmission Owner, and Distribution Provider shall keep
data or evidence to show compliance as identified below unless directed by its
CEA to retain specific evidence for a longer period of time as part of an
investigation:
•

•

The Generator Owner, Transmission Owner, and Distribution Provider shall
retain evidence of Requirement R1 and Measure M1 for the most recent
three calendar years.
If a Generator Owner, Transmission Owner, or Distribution Provider is
found non-compliant, it shall keep information related to the noncompliance until mitigation is complete and approved or for the time
specified above, whichever is longer.

The CEA 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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PRC-025-1— Generator Relay Loadability

Table of Compliance Elements
R#

Time
Horizon

Long-Term
Planning

Violation Severity Levels
VRF
Lower VSL

High

Moderate VSL

N/A

High VSL

Severe VSL

N/A

The Generator Owner,
Transmission Owner,
and Distribution Provider
did not apply settings in
accordance with PRC025-1 – Attachment 1:
Relay Settings, on an
applied load-responsive
protective relay.

D. Regional Variances

None.
E. Interpretations

None.
F. Associated Documents

NERC System Protection and Control Subcommittee, July 2010, “Power Plant and Transmission System Protection
Coordination.”
IEEE C37.102-2006, “Guide for AC Generator Protection.”

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PRC-025-1— Generator Relay Loadability

PRC-025-1 – Attachment 1: Relay Settings
Introduction
This standard does not require the Generator Owner, Transmission Owner, or Distribution Provider to use any of the protective
functions listed in Table 1. Each Generator Owner, Transmission Owner, and Distribution Provider that applies load-responsive
protective relays on their respective Elements listed in 3.2, Facilities, shall use one of the following Options in Table 1, Relay
Loadability Evaluation Criteria (“Table 1”), to set each load-responsive protective relay element according to its application and relay
type. The bus voltage is based on the criteria for the various applications listed in Table 1.
Generators
Synchronous generator relay pickup setting criteria values are derived from the unit’s maximum gross Real Power capability, in
megawatts (MW), as reported to the Transmission Planner, and the unit’s Reactive Power capability, in megavoltampere-reactive
(Mvar), is determined by calculating the MW value based on the unit’s nameplate megavoltampere (MVA) rating at rated power
factor. If different seasonal capabilities are reported, the maximum capability shall be used for the purposes of this standard.
Asynchronous generator relay pickup setting criteria values (including inverter-based installations) are derived from the site’s
aggregate maximum complex power capability, in MVA, as reported to the Transmission Planner, including the Mvar output of any
static or dynamic reactive power devices.
For the application case where synchronous and asynchronous generator types are combined on a generator step-up transformer or on
Elements that connect the generator step-up (GSU) transformer(s) to the Transmission system that are used exclusively to export
energy directly from a BES generating unit or generating plant (Elements may also supply generating plant loads.), the pickup setting
criteria shall be determined by vector summing the pickup setting criteria of each generator type, and using the bus voltage for the
given synchronous generator application and relay type.
Transformers
Calculations using the GSU transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers with
deenergized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest
generator bus voltage. When the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the
nominal GSU transformer turns ratio shall be used.
Applications that use more complex topology, such as generators connected to a multiple winding transformer, are not directly
addressed by the criteria in Table 1. These topologies can result in complex power flows, and may require simulation to avoid overly
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conservative assumptions to simplify the calculations. Entities with these topologies should set their relays in such a way that they do
not operate for the conditions being addressed in this standard.
Multiple Lines
Applications that use more complex topology, such as multiple lines that connect the generator step-up (GSU) transformer(s) to the
Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may
also supply generating plant loads) are not directly addressed by the criteria in Table 1. These topologies can result in complex power
flows, and it may require simulation to avoid overly conservative assumptions to simplify the calculations. Entities with these
topologies should set their relays in such a way that they do not operate for the conditions being addressed in this standard.
Exclusions
The following protection systems are excluded from the requirements of this standard:
1. Any relay elements that are in service only during start up.
2. Load-responsive protective relay elements that are armed only when the generator is disconnected from the system, (e.g., nondirectional overcurrent elements used in conjunction with inadvertent energization schemes, and open breaker flashover
schemes).
3. Phase fault detector relay elements employed to supervise other load-responsive phase distance elements (e.g., in order to
prevent false operation in the event of a loss of potential) provided the distance element is set in accordance with the criteria
outlined in the standard.
4. Protective relay elements that are only enabled when other protection elements fail (e.g., overcurrent elements that are only
enabled during loss of potential conditions).
5. Protective relay elements used only for Special Protection Systems that are subject to one or more requirements in a NERC or
Regional Reliability Standard.
6. Protection systems that detect generator overloads that are designed to coordinate with the generator short time capability by
utilizing an extremely inverse characteristic set to operate no faster than 7 seconds at 218% of fullload current (e.g., rated
armature current), and prevent operation below 115% of full-load current.3
7. Protection systems that detect transformer overloads and are designed only to respond in time periods which allow an operator
15 minutes or greater to respond to overload conditions.
3

IEEE C37.102-2006, “Guide for AC Generator Protection,” Section 4.1.1.2.
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PRC-025-1— Generator Relay Loadability

Table 1
Table 1 beginning on the next page is structured and formatted to aid the reader with identifying an option for a given load-responsive
protective relay.
The first column identifies the application (e.g., synchronous or asynchronous generators, generator step-up transformers, unit
auxiliary transformers, Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export
energy directly from a BES generating unit or generating plant. Elements may also supply generating plant loads). Dark blue
horizontal bars, excluding the header which repeats at the top of each page, demarcate the various applications.
The second column identifies the load-responsive protective relay (e.g., 21, 50, 51, 51V-C, 51V-R, or 67) according to the applied
application in the first column. A light blue horizontal bar between the relay types is the demarcation between relay types for a given
application. These light blue bars will contain no text.
The third column uses numeric and alphabetic options (i.e., index numbering) to identify the available options for setting loadresponsive protective relays according to the application and applied relay type. Another, shorter, light blue bar contains the word
“OR,” and reveals to the reader that the relay for that application has one or more options (i.e., “ways”) to determine the bus voltage
and pickup setting criteria in the fourth and fifth column, respectively. The bus voltage column and pickup setting criteria columns
provide the criteria for determining an appropriate setting.
The table is further formatted by shading groups of relays associated with asynchronous generator applications. Synchronous
generator applications and the unit auxiliary transformer applications are not shaded. Also, intentional buffers were added to the table
such that similar options, as possible, would be paired together on a per page basis. Note that some applications may have an
additional pairing that might occur on adjacent pages.

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Relay Type

Option

Bus Voltage4

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The impedance element shall be set less than the calculated
impedance derived from 115% of:
(1) Real Power output – 100% of the gross MW capability
reported to the Transmission Planner, and
(2) Reactive Power output – 150% of the MW value, derived
from the generator nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the
transformer turns ratio and
impedance)

Simulated generator bus voltage
coincident with the highest Reactive
Power output achieved during fieldforcing in response to a 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer prior to field-forcing

The impedance element shall be set less than the calculated
impedance derived from 115% of:
(1) Real Power output – 100% of the gross MW capability
reported to the Transmission Planner, and
(2) Reactive Power output –100% of the maximum gross Mvar
output during field-forcing as determined by simulation

Pickup Setting Criteria

Synchronous
generating unit(s), or
Elements utilized in
the aggregation of
dispersed power
producing resources

Phase distance relay
(21) – directional
toward the
Transmission
system

The same application continues on the next page with a different relay type

Calculations using the generator step-up (GSU) transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers with
deenergized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest generator bus voltage. When
the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU turns ratio shall be used.
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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Relay Type

Option

Bus Voltage4

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the gross MW capability
reported to the Transmission Planner, and
(2) Reactive Power output – 150% of the MW value, derived
from the generator nameplate MVA rating at rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the
transformer turns ratio and
impedance)

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the gross MW capability
reported to the Transmission Planner or, and
(2) Reactive Power output –100% of the maximum gross Mvar
output during field-forcing as determined by simulation

Pickup Setting Criteria

Synchronous
generating unit(s), or
Elements utilized in
the aggregation of
dispersed power
producing resources

Phase time
overcurrent relay
(51) or (51V-R) –
voltage-restrained

The same application continues with a different relay type below
Phase time
overcurrent relay
(51V-C) – voltage
controlled (Enabled
to operate as a
function of voltage)

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

Voltage control setting shall be set less than 75% of the
calculated generator bus voltage

A different application starts on the next page

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Relay Type
Phase distance relay
(21) – directional
toward the
Transmission
system

Asynchronous
generating unit(s)
(including inverterbased installations),
or Elements utilized
in the aggregation of
dispersed power
producing resources

Phase time
overcurrent relay
(51) or (51V-R) –
voltage-restrained

Phase time
overcurrent relay
(51V-C) – voltage
controlled (Enabled
to operate as a
function of voltage)

Option

Bus Voltage4

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The impedance element shall be set less than the calculated
impedance derived from 130% of the maximum aggregate
nameplate MVA output at rated power factor (including the
Mvar output of any static or dynamic reactive power devices)

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The overcurrent element shall be set greater than 130% of the
calculated current derived from the maximum aggregate
nameplate MVA output at rated power factor (including the
Mvar output of any static or dynamic reactive power devices)

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

Voltage control setting shall be set less than 75% of the
calculated generator bus voltage

Pickup Setting Criteria

A different application starts on the next page

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Relay Type

Option

Generator step-up
transformer(s)
connected to
synchronous
generators

Phase distance relay
(21) – directional
toward the
Transmission
system – installed
on generator-side of
the GSU
transformer
If the relay is
installed on the
high-side of the
GSU transformer
use Option 14

Bus Voltage4

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The impedance element shall be set less than the calculated
impedance derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output – 150% of the aggregate generation
MW value, derived from the generator nameplate MVA rating at
rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the
transformer turns ratio and
impedance)

The impedance element shall be set less than the calculated
impedance derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined
by simulation

The same application continues on the next page with a different relay type

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Relay Type

Option

Generator step-up
transformer(s)
connected to
synchronous
generators

Phase time
overcurrent relay
(51) – installed on
generator-side of the
GSU transformer
If the relay is
installed on the
high-side of the
GSU transformer
use Option 15

Bus Voltage4

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output – 150% of the aggregate generation
MW value, derived from the generator nameplate MVA rating at
rated power factor

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the
transformer turns ratio and
impedance)

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined
by simulation

The same application continues on the next page with a different relay type

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Relay Type

Option

Generator step-up
transformer(s)
connected to
synchronous
generators

Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system – installed
on generator-side of
the GSU
transformer
If the relay is
installed on the
high-side of the
GSU transformer
use Option 16

Bus Voltage4

Pickup Setting Criteria

Generator bus voltage corresponding
to 0.95 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

Calculated generator bus voltage
corresponding to 0.85 per unit
nominal voltage on the high-side
terminals of the generator step-up
transformer (including the
transformer turns ratio and
impedance)

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined
by simulation

A different application starts on the next page

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Generator step-up
transformer(s)
connected to
asynchronous
generators only
(including inverterbased installations)

Relay Type
Phase distance relay
(21) – directional
toward the
Transmission
system – installed
on generator-side of
the GSU
transformer
If the relay is
installed on the
high-side of the
GSU transformer
use Option 17

Phase time
overcurrent relay
(51) – installed on
generator-side of the
GSU transformer
If the relay is
installed on the
high-side of the
GSU transformer
use Option 18

Option

Bus Voltage4

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer
for overcurrent relays installed on the
low-side

Pickup Setting Criteria

The same application continues on the next page with a different relay type

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Generator step-up
transformer(s)
connected to
asynchronous
generators only
(including inverterbased installations)

Relay Type
Phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system – installed
on generator-side of
the GSU
transformer

Option

Bus Voltage4

Generator bus voltage corresponding
to 1.0 per unit of the high-side
nominal voltage times the turns ratio
of the generator step-up transformer

Pickup Setting Criteria

If the relay is
installed on the
high-side of the
GSU transformer
use Option 19
A different application starts below

Unit auxiliary
transformer(s) (UAT)

Phase time
overcurrent relay
(51) applied at the
high-side terminals
of the UAT, for
which operation of
the relay will cause
the associated
generator to trip.

13a

1.0 per unit of the winding nominal
voltage of the unit auxiliary
transformer

The overcurrent element shall be set greater than 150% of the
calculated current derived from the unit auxiliary transformer
maximum nameplate MVA rating

Unit auxiliary transformer bus
voltage corresponding to the
measured current

The overcurrent element shall be set greater than 150% of the
unit auxiliary transformer measured current at the generator
maximum gross MW capability reported to the Transmission
Planner

13b

A different application starts on the next page

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Elements that
connect the GSU
transformer(s) to the
Transmission system
that are used
exclusively to export
energy directly from
a BES generating unit
or generating plant.
Elements may also
supply generating
plant loads. –
connected to
synchronous
generators

Relay Type

Phase distance relay
(21) – directional
toward the
Transmission
system – installed
on the high-side of
the GSU
transformer
If the relay is
installed on the
generator-side of the
GSU transformer
use Option 7

Option

14a

Bus Voltage4

Pickup Setting Criteria

0.85 per unit of the line nominal
voltage

The impedance element shall be set less than the calculated
impedance derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output – 120% of the aggregate generation
MW value, derived from the generator nameplate MVA rating at
rated power factor

Simulated line voltage coincident
with the highest Reactive Power
output achieved during field-forcing
in response to a 0.85 per unit nominal
voltage on the high-side terminals of
the generator step-up transformer
prior to field-forcing

The impedance element shall be set less than the calculated
impedance derived from 115% of:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined
by simulation

14b

The same application continues on the next page with a different relay type

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Elements that
connect the GSU
transformer(s) to the
Transmission system
that are used
exclusively to export
energy directly from
a BES generating unit
or generating plant.
Elements may also
supply generating
plant loads. –
connected to
synchronous
generators

Relay Type
Phase overcurrent
supervisory element
(50) – associated
with current-based,
communicationassisted schemes
where the scheme is
capable of tripping
for loss of
communications
installed on the
high-side of the
GSU transformer or
phase time
overcurrent relay
(51) – installed on
the high-side of the
GSU transformer
If the relay is
installed on the
generator-side of the
GSU transformer
use Option 8

Option

15a

Bus Voltage4

Pickup Setting Criteria

0.85 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output – 120% of the aggregate generation
MW value, derived from the generator nameplate MVA rating at
rated power factor

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined
by simulation

15b

The same application continues on the next page with a different relay type

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Elements that
connect the GSU
transformer(s) to the
Transmission system
that are used
exclusively to export
energy directly from
a BES generating unit
or generating plant.
Elements may also
supply generating
plant load. –
connected to
synchronous
generators

Relay Type
Phase directional
overcurrent
supervisory element
(67) – associated
with current-based,
communicationassisted schemes
where the scheme is
capable of tripping
for loss of
communications
directional toward
the Transmission
system installed on
the high-side of the
GSU transformer or
phase directional
time overcurrent
relay (67) –
directional toward
the Transmission
system installed on
the high-side of the
GSU transformer

Option

16a

Bus Voltage4

Pickup Setting Criteria

0.85 per unit of the line nominal
voltage

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output – 120% of the aggregate generation
MW value, derived from the generator nameplate MVA rating at
rated power factor

The overcurrent element shall be set greater than 115% of the
calculated current derived from:
(1) Real Power output – 100% of the aggregate generation gross
MW reported to the Transmission Planner, and
(2) Reactive Power output –100% of the aggregate generation
maximum gross Mvar output during field-forcing as determined
by simulation

16b

If the relay is
installed on the
generator-side of the
GSU transformer
use Option 9
A different application starts on the next page

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Relay Type
Phase distance relay
(21) – directional
toward the
Transmission
system– installed on
the high-side of the
GSU transformer

Elements that
connect the GSU
transformer(s) to the
Transmission system
that are used
exclusively to export
energy directly from
a BES generating unit
or generating plant.
Elements may also
supply generating
plant loads. –
connected to
asynchronous
generators only
(including inverterbased installations)

If the relay is
installed on the
generator-side of the
GSU transformer
use Option 10

Option

Bus Voltage4

1.0 per unit of the line nominal
voltage

Pickup Setting Criteria

The same application continues on the next page with a different relay type

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Elements that
connect the GSU
transformer(s) to the
Transmission system
that are used
exclusively to export
energy directly from
a BES generating unit
or generating plant.
Elements may also
supply generating
plant loads. –
connected to
asynchronous
generators only
(including inverterbased installations)

Relay Type
Phase overcurrent
supervisory element
(50) – associated
with current-based,
communicationassisted schemes
where the scheme is
capable of tripping
for loss of
communications
installed on the
high-side of the
GSU transformer or
Phase time
overcurrent relay
(51) – installed on
the high-side of the
GSU transformer

Option

Bus Voltage4

1.0 per unit of the line nominal
voltage

Pickup Setting Criteria

If the relay is
installed on the
generator-side of the
GSU transformer
use Option 11

The same application continues on the next page with a different relay type

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PRC-025-1— Generator Relay Loadability

Table 1. Relay Loadability Evaluation Criteria
Application

Elements that
connect the GSU
transformer(s) to the
Transmission system
that are used
exclusively to export
energy directly from
a BES generating unit
or generating plant.
Elements may also
supply generating
plant loads. –
connected to
asynchronous
generators only
(including inverterbased installations)

Relay Type
Phase directional
overcurrent
supervisory element
(67) – associated
with current-based,
communicationassisted schemes
where the scheme is
capable of tripping
for loss of
communications
directional toward
the Transmission
system installed on
the high-side of the
GSU transformer or
Phase directional
time overcurrent
relay (67) – installed
on the high-side of
the GSU
transformer

Option

Bus Voltage4

1.0 per unit of the line nominal
voltage

Pickup Setting Criteria

If the relay is
installed on the
generator-side of the
GSU transformer
use Option 12
End of Table 1

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PRC-025-1— Application Guidelines

PRC-025-1 Guidelines and Technical Basis
Introduction
The document, “Power Plant and Transmission System Protection Coordination,” published by
the NERC System Protection and Control Subcommittee (SPCS) provides extensive general
discussion about the protective functions and generator performance addressed within this
standard. This document was last revised in July 2010.5
The basis for the standard’s loadability criteria for relays applied at the generator terminals or
low-side of the generator step-up (GSU) transformer is the dynamic generating unit loading
values observed during the August 14, 2003 blackout, other subsequent system events, and
simulations of generating unit response to similar system conditions. The Reactive Power output
observed during field-forcing in these events and simulations approaches a value equal to 150
percent of the Real Power megawatt (MW) capability of the generating unit when the generator
is operating at its Real Power capability. In the SPCS technical reference document, two
operating conditions were examined based on these events and simulations: (1) when the unit is
operating at rated Real Power in MW with a level of Reactive Power output in megavoltamperereactive (Mvar) which is equivalent to 150 percent times the rated MW value (representing some
level of field-forcing) and (2) when the unit is operating at its declared low active Real Power
operating limit (e.g., 40 percent of rated Real Power) with a level of Reactive Power output in
Mvar which is equivalent to 175 percent times the rated MW value (representing some additional
level of field-forcing).
Both conditions noted above are evaluated with the GSU transformer high-side voltage at 0.85
per unit. These load operating points are believed to be conservatively high levels of Reactive
Power out of the generator with a 0.85 per unit high-side voltage which was based on these
observations. However, for the purposes of this standard it was determined that the second load
point (40 percent) offered no additional benefit and only increased the complexity for an entity to
determine how to comply with the standard. Given the conservative nature of the criteria, which
may not be achievable by all generating units, an alternate method is provided to determine the
Reactive Power output by simulation. Also, to account for Reactive Power losses in the GSU
transformer, a reduced level of output of 120 percent times the rated MW value is provided for
relays applied at the high-side of the GSU transformer(s) and on Elements that connect the GSU
transformer(s) to the Transmission system and are used exclusively to export energy directly
from a BES generating unit or generating plant. Elements may also supply generating plant
loads.
The phrase, “while maintaining reliable fault protection” in Requirement R1, describes that the
Generator Owner, Transmission Owner, and Distribution Provider is to comply with this
standard while achieving its desired protection goals. Load-responsive protective relays, as
addressed within this standard, may be intended to provide a variety of backup protection
functions, both within the generating unit or generating plant and on the Transmission system,
and this standard is not intended to result in the loss of these protection functions. Instead, it is
suggested that the Generator Owner, Transmission Owner, and Distribution Provider consider
both the requirement within this standard and its desired protection goals, and perform
modifications to its protective relays or protection philosophies as necessary to achieve both.
5

http://www.nerc.com/docs/pc/spctf/Gen%20Prot%20Coord%20Rev1%20Final%2007-30-2010.pdf
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PRC-025-1— Application Guidelines

For example, if the intended protection purpose is to provide backup protection for a failed
Transmission breaker, it may not be possible to achieve this purpose while complying with this
standard if a simple mho relay is being used. In this case, it may be possible to meet this purpose
by replacing the legacy relay with a modern advanced-technology relay that can be set using
functions such as load encroachment. It may otherwise be necessary to reconsider whether this is
an appropriate method of achieving protection for the failed Transmission breaker, and whether
this protection can be better provided by, for example, applying a breaker failure relay with a
transfer trip system.
Requirement R1 establishes that the Generator Owner, Transmission Owner, and Distribution
Provider must understand the applications of PRC-025-1 – Attachment 1: Relay Settings, Table
1: Relay Loadability Evaluation Criteria (“Table 1”) in determining the settings that it must
apply to each of its load-responsive protective relays to prevent an unnecessary trip of its
generator during the system conditions anticipated by this standard.
Applicability
To achieve the reliability objective of this standard it is necessary to include all load-responsive
protective relays that are affected by increased generator output in response to system
disturbances. This standard is therefore applicable to relays applied by the Generator Owner,
Transmission Owner, and Distribution Provider at the terminals of the generator, GSU
transformer, unit auxiliary transformer (UAT), Elements that connect the GSU transformer(s) to
the Transmission system that are used exclusively to export energy directly from a BES
generating unit or generating plant (Elements may also supply generating plant loads.), and
Elements utilized in the aggregation of dispersed power producing resources.
The Generator Owner’s interconnection facility (in some cases labeled a “transmission Facility”
or “generator leads”) consists of Elements between the GSU transformer and the interface with
the portion of the Bulk Electric System (BES) where Transmission Owners take over the
ownership. This standard does not use the industry recognized term “generator interconnection
Facility” consistent with the work of Project 2010-07 (Generator Requirements at the
Transmission Interface), because the term generator interconnection Facility generally implies
ownership by the Generator Owner. Instead, this standard refers to these Facilities as “Elements
that connect the GSU transformer(s) to the Transmission system that are used exclusively to
export energy directly from a BES generating unit or generating plant. Elements may also supply
generating plant loads.” to include these Facilities when they are also owned by the Transmission
Owner or Distribution Provider. The load-responsive protective relays in this standard for which
an entity shall be in compliance is dependent on the location and the application of the protective
functions. Figures 1, 2, and 3 illustrate various generator interface connections with the
Transmission system.
This standard is applicable to Elements utilized in the aggregation of dispersed power producing
resources (in some cases referred to as a “collector system”) consist of the Elements between
individual generating units and the common point of interconnection to the Transmission system.

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PRC-025-1— Application Guidelines

Figure 1
Figure 1 is a single (or set) of generators connected to the Transmission system through a radial
line that is used exclusively to export energy directly from a BES generating unit or generating
plant to the network. Elements may also supply generating plant loads. The protective relay R1
located on the high-side of the GSU transformer breaker CB100 is generally applied to provide
backup protection to the relaying located at Bus A and in some cases Bus B. Under this
application, relay R1 would apply the loadability requirement in PRC-025-1 using an appropriate
option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect
the GSU transformer(s) to the Transmission system that are used exclusively to export energy
directly from a BES generating unit or generating plant. Elements may also supply generating
plant loads.
The protective relay R2 located on the incoming source breaker CB102 to the generating plant
applies relaying that primarily protects the line by using line differential relaying from Bus A to
B and also provides backup protection to the transmission relaying at Bus B. In this case, the
relay function that provides line protection would apply the loadability requirement in PRC-0251 and an appropriate option for the application from Table 1 (e.g., 15a, 15b, 16a, 16b, 18, and 19)
for phase overcurrent supervisory elements (i.e., phase fault detectors) associated with currentbased, communication-assisted schemes (i.e., pilot wire, phase comparison, and line current
differential) where the scheme is capable of tripping for loss of communications. The backup
protective function would apply the requirement in the PRC-025-1 standard using an appropriate
option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect
the GSU transformer(s) to the Transmission system that are used exclusively to export energy
directly from a BES generating unit or generating plant. Elements may also supply generating
plant loads.
In this particular case, the applicable responsible entity’s directional relay R3 located on breaker
CB103 at Bus B looking toward Bus A (i.e., generation plant) is not included in either loadability
standard (i.e., PRC-023 or PRC-025) since it is not affected by increased generator output in
response to system disturbances described in this standard or by increased transmission system
loading described in PRC-023. Any protective element set to protect in the direction from Bus A
to B is included within the PRC-025-1 standard. PRC-025-1 is applicable to Relay R3, for
example, if the relay is applied and set to trip for a reverse element directional toward the
Transmission system.

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PRC-025-1— Application Guidelines

Figure 1. Generation exported through a single radial line.

Figure 2
Figure 2 is an example of a single (or set) of generators connected to the Transmission system
through multiple lines that are used exclusively to export energy directly from a BES generating
unit or generating plant to the network. Elements may also supply generating plant loads. The
protective relay R1 on the high-side of the GSU transformer breaker CB100 is generally applied
to provide backup protection to the Transmission relaying located at Bus A and in some cases
Bus B. Under this application, relay R1 would apply the loadability requirement in PRC-025-1
using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for
Elements that connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or generating plant. Elements
may also supply generating plant loads.
The protective relays R2 and R3 located on the incoming source breakers CB102 and CB103 to
the generating plant applies relaying that primarily protects the line from Bus A to B and also
provides backup protection to the transmission relaying at Bus B. In this case, the relay function
that provides line protection would apply the loadability requirement in PRC-025-1 and an
appropriate option for the application from Table 1 (e.g., Options 15a, 15b, 16a, 16b, 18, and 19)
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PRC-025-1— Application Guidelines

for phase overcurrent supervisory elements (i.e., phase fault detectors) associated with currentbased, communication-assisted schemes (i.e., pilot wire, phase comparison, and line current
differential) where the scheme is capable of tripping for loss of communications. The backup
protective function would apply the requirement in the PRC-025-1 standard using an appropriate
option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect
the GSU transformer(s) to the Transmission system that are used exclusively to export energy
directly from a BES generating unit or generating plant. Elements may also supply generating
plant loads.
In this particular case, the applicable responsible entity’s directional relay R4 and R5 located on
the breakers CB104 and CB105, respectively at Bus B looking into the generation plant are not
included in either loadability standard (i.e., PRC-023 or PRC-025) since they are not subject to
the stressed loading requirements described in the standard or by increased transmission system
loading described in PRC-023. Any protective element set to protect in the direction from Bus A
to B is included within the PRC-025-1 standard. PRC-025-1 is applicable to Relay R4 and R5,
for example, if the relays are applied and set to trip for a reverse element directional toward the
Transmission system.

Figure 2. Generation exported through multiple radial lines.

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PRC-025-1— Application Guidelines

Figure 3
Figure 3 is example a single (or set) of generators exporting power dispersed through multiple
lines to the Transmission system through a network. The protective relay R1 on the high-side of
the GSU transformer breaker CB100 is generally applied to provide backup protection to the
Transmission relaying located at Bus A and in some cases Bus C or Bus D. Under this
application, relay R1 would apply the applicable loadability requirement in PRC-025-1 using an
appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements
that connect the GSU transformer(s) to the Transmission system that are used exclusively to
export energy directly from a BES generating unit or generating plant. Elements may also supply
generating plant loads.
Since the lines from Bus A to Bus C and from Bus A to Bus D are part of the transmission
network, these lines would not be considered as Elements that connect the GSU transformer(s) to
the Transmission system that are used exclusively to export energy directly from a BES
generating unit or generating plant. Elements may also supply generating plant loads. Therefore,
the applicable responsible entity would be responsible for the load-responsive protective relays
R2 and R3 under the PRC-023 standard. The applicable responsible entity’s loadability relays R4
and R5 located on the breakers CB104 and CB105 at Bus C and D are also subject to the
requirements of the PRC-023 standard.

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PRC-025-1— Application Guidelines

Figure 3. Generation exported through a network.

This standard is also applicable to the UAT(s) that supply station service power to support the
on-line operation of generating units or generating plants. These transformers are variably
referred to as station power, unit auxiliary transformer(s), or station service transformer(s) used
to provide overall auxiliary power to the generator station when the generator is running.
Inclusion of these transformers satisfies a directive in FERC Order No. 733, paragraph 104,
which directs NERC to include in this standard a loadability requirement for relays used for
overload protection of the UAT(s) that supply normal station service for a generating unit.
Synchronous Generator Performance
When a synchronous generator experiences a depressed voltage, the generator will respond by
increasing its Reactive Power output to support the generator terminal voltage. This operating
condition, known as “field-forcing,” results in the Reactive Power output exceeding the steadystate capability of the generator and may result in operation of generation system load-responsive
protective relays if they are not set to consider this operating condition. The ability of the
generating unit to withstand the increased Reactive Power output during field-forcing is limited
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PRC-025-1— Application Guidelines

by the field winding thermal withstand capability. The excitation limiter will respond to begin
reducing the level of field-forcing in as little as one second, but may take much longer,
depending on the level of field-forcing given the characteristics and application of the excitation
system. Since this time may be longer than the time-delay of the generator load-responsive
protective relay, it is important to evaluate the loadability to prevent its operation for this
condition.
The generator bus voltage during field-forcing will be higher than the high-side voltage due to
the voltage drop across the GSU transformer. When the relay voltage is supplied from the
generator bus, it is necessary to assess loadability using the generator bus voltage. The criteria
established within Table 1 are based on 0.85 per unit of Transmission system nominal voltage.
This voltage was widely observed during the events of August 14, 2003, and was determined
during the analysis of the events to represent a condition from which the System may have
recovered, had not other undesired behavior occurred.
The dynamic load levels specified in Table 1 under column “Pickup Setting Criteria” are
representative of the maximum expected apparent power during field-forcing with the
Transmission system voltage at 0.85 per unit, for example, at the high-side of the GSU
transformer. These values are based on records from the events leading to the August 14, 2003
blackout, other subsequent System events, and simulations of generating unit responses to
similar conditions. Based on these observations, the specified criteria represent conservative but
achievable levels of Reactive Power output of the generator with a 0.85 per unit high-side
voltage at the point of interconnection.
The dynamic load levels were validated by simulating the response of synchronous generating
units to depressed Transmission system voltages for 67 different generating units. The generating
units selected for the simulations represented a broad range of generating unit and excitation
system characteristics as well as a range of Transmission system interconnection characteristics.
The simulations confirmed, for units operating at or near the maximum Real Power output, that it
is possible to achieve a Reactive Power output of 1.5 times the rated Real Power output when the
Transmission system voltage is depressed to 0.85 per unit. While the simulations demonstrated
that all generating units may not be capable of this level of Reactive Power output, the
simulations confirmed that approximately 20 percent of the units modeled in the simulations
could achieve these levels. On the basis of these levels, Table 1, Options 1a (i.e., 0.95 per unit)
and 1b (i.e., 0.85 per unit), for example, are based on relatively simple, but conservative
calculations of the high-side nominal voltage. In recognition that not all units are capable of
achieving this level of output Option 1c (i.e., simulation) was developed to allow the Generator
Owner, Transmission Owner, or Distribution Provider to simulate the output of a generating unit
when the simple calculation is not adequate to achieve the desired protective relay setting.
Dispersed Generation
This standard is applicable to dispersed generation such as wind farms and solar arrays. The
intent of this standard is to ensure the aggregate facility as defined above will remain on-line
during a system disturbance; therefore, all output load-responsive protective elements associated
with the facility are included in PRC-025.

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Individual dispersed power producing resources that comprise an aggregated facility will behave
similarly for the system conditions described in the Introduction above and addressed within this
standard. Therefore, it is necessary to apply the criteria to each individual power producing
resource.
The Elements utilized in the aggregation of dispersed power producing resources will be
subjected to the effects of all dispersed power producing resources aggregated on those
Elements. Therefore, the criteria applied to the individual dispersed power producing resources
will also apply to the aggregation Elements.
Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a system designed primarily for aggregating capacity,
connected at a common point at a voltage of 100 kV or above are included in PRC-025-1. Loadresponsive protective relays that are applied on Elements that connect these individual generating
units through the point of interconnection with the Transmission system are within the scope of
PRC-025-1. For example, feeder overcurrent relays and feeder step-up transformer overcurrent
relays (see Figure 5) are included because these relays are challenged by generator output.
In the case of solar arrays where there are multiple voltages utilized in converting the solar panel
DC output to a 60Hz AC waveform, the “terminal” is defined at the 60Hz AC output of the
inverter-solar panel combination.
Asynchronous Generator Performance
Asynchronous generators, however, do not have excitation systems and will not respond to a
disturbance with the same magnitude of apparent power that a synchronous generator will
respond. Asynchronous generators, though, will support the system during a disturbance.
Inverter-based generators will provide Real Power and Reactive Power (depending on the
installed capability and regional grid code requirements) and may even provide a faster Reactive
Power response than a synchronous generator. The magnitude of this response may slightly
exceed the steady-state capability of the inverter but only for a short duration before a crowbar
function will activate. Although induction generators will not inherently supply Reactive Power,
induction generator installations may include static and/or dynamic reactive devices, depending
on regional grid code requirements. These devices also may provide Real Power during a voltage
disturbance. Thus, tripping asynchronous generators may exacerbate a disturbance.
Inverters, including wind turbines (i.e., Types 3 and 4) and photovoltaic solar, are commonly
available with 0.90 power factor capability. This calculates to an apparent power magnitude of
1.11 per unit of rated MW.
Similarly, induction generator installations, including Type 1 and Type 2 wind turbines, often
include static and/or dynamic reactive devices to meet grid code requirements and may have
apparent power output similar to inverter-based installations; therefore, it is appropriate to use
the criteria established in the Table 1 (i.e., Options 4, 5, 6, 10, 11, 12, 17, 18, and 19) for
asynchronous generator installations.

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Synchronous Generator Simulation Criteria
The Generator Owner, Transmission Owner, or Distribution Provider who elects a simulation
option to determine the synchronous generator performance on which to base relay settings may
simulate the response of a generator by lowering the Transmission system voltage on the highside of the GSU transformer. This can be simulated by means such as modeling the connection
of a shunt reactor on the Transmission system to lower the GSU transformer high-side voltage to
0.85 per unit prior to field-forcing. The resulting step change in voltage is similar to the sudden
voltage depression observed in parts of the Transmission system on August 14, 2003. The initial
condition for the simulation should represent the generator at 100 percent of the maximum gross
Real Power capability in MW as reported to the Transmission Planner. The simulation is used to
determine the Reactive Power and voltage to be used to calculate relay pickup setting limits. The
Reactive Power value obtained by simulation is the highest simulated level of Reactive Power
achieved during field-forcing. The voltage value obtained by simulation is the simulated voltage
coincident with the highest Reactive Power achieved during field-forcing. These values of
Reactive Power and voltage correspond to the minimum apparent impedance and maximum
current observed during field-forcing.
Phase Distance Relay – Directional Toward Transmission System (21)
Generator phase distance relays that are directional toward the Transmission system, whether
applied for the purpose of primary or backup GSU transformer protection, external system
backup protection, or both, were noted during analysis of the August 14, 2003 disturbance event
to have unnecessarily or prematurely tripped a number of generating units or generating plants,
contributing to the scope of that disturbance. Specifically, eight generators are known to have
been tripped by this protection function. These options establish criteria for phase distance relays
that are directional toward the Transmission system to help assure that generators, to the degree
possible, will provide System support during disturbances in an effort to minimize the scope of
those disturbances.
The phase distance relay that is directional toward the Transmission system measures impedance
derived from the quotient of generator terminal voltage divided by generator stator current.
Section 4.6.1.1 of IEEE C37.102-2006, “Guide for AC Generator Protection,” describes the
purpose of this protection as follows (emphasis added):
“The distance relay applied for this function is intended to isolate
the generator from the power system for a fault that is not cleared
by the transmission line breakers. In some cases this relay is set
with a very long reach. A condition that causes the generator
voltage regulator to boost generator excitation for a sustained
period may result in the system apparent impedance, as monitored
at the generator terminals, to fall within the operating
characteristics of the distance relay. Generally, a distance relay
setting of 150% to 200% of the generator MVA rating at its rated
power factor has been shown to provide good coordination for
stable swings, system faults involving in-feed, and normal loading
conditions. However, this setting may also result in failure of the
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PRC-025-1— Application Guidelines

relay to operate for some line faults where the line relays fail to
clear. It is recommended that the setting of these relays be
evaluated between the generator protection engineers and the
system protection engineers to optimize coordination while still
protecting the turbine generator. Stability studies may be needed
to help determine a set point to optimize protection and
coordination. Modern excitation control systems include
overexcitation limiting and protection devices to protect the
generator field, but the time delay before they reduce excitation is
several seconds. In distance relay applications for which the
voltage regulator action could cause an incorrect trip,
consideration should be given to reducing the reach of the relay
and/or coordinating the tripping time delay with the time delays of
the protective devices in the voltage regulator. Digital
multifunction relays equipped with load encroachment binders
[sic] can prevent misoperation for these conditions. Within its
operating zone, the tripping time for this relay must coordinate
with the longest time delay for the phase distance relays on the
transmission lines connected to the generating substation bus.
With the advent of multifunction generator protection relays, it is
becoming more common to use two-phase distance zones. In this
case, the second zone would be set as previously described. When
two zones are applied for backup protection, the first zone is
typically set to see the substation bus (120% of the GSU
transformer). This setting should be checked for coordination with
the zone-1 element on the shortest line off of the bus. The normal
zone-2 time-delay criteria would be used to set the delay for this
element. Alternatively, zone-1 can be used to provide high-speed
protection for phase faults, in addition to the normal differential
protection, in the generator and iso-phase bus with partial
coverage of the GSU transformer. For this application, the element
would typically be set to 50% of the transformer impedance with
little or no intentional time delay. It should be noted that it is
possible that this element can operate on an out-of-step power
swing condition and provide misleading targeting.”
If a mho phase distance relay that is directional toward the Transmission system cannot be set to
maintain reliable fault protection and also meet the criteria in accordance with Table 1, there may
be other methods available to do both, such as application of blinders to the existing relays,
implementation of lenticular characteristic relays, application of offset mho relays, or
implementation of load encroachment characteristics. Some methods are better suited to
improving loadability around a specific operating point, while others improve loadability for a
wider area of potential operating points in the R-X plane. The operating point for a stressed
System condition can vary due to the pre-event system conditions, severity of the initiating
event, and generator characteristics such as Reactive Power capability.
For this reason, it is important to consider the potential implications of revising the shape of the
relay characteristic to obtain a longer relay reach, as this practice may result in a relay
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characteristic that overlaps the capability of the generating unit when operating at a Real Power
output level other than 100 percent of the maximum Real Power capability. Overlap of the relay
characteristic and generator capability could result in tripping the generating unit for a loading
condition within the generating unit capability. The examples in Appendix E of the Power Plant
and Transmission System Protection Coordination technical reference document illustrate the
potential for, and need to avoid, encroaching on the generating unit capability.
Phase Instantaneous and Time Overcurrent Relay (50/51)
See section 3.9.2 of the Power Plant and Transmission System Protection Coordination technical
reference document for a detailed discussion of this protection function. Note that the Table 1
setting criteria established within the Table 1 options differ from section 3.9.2 of the Power Plant
and Transmission System Protection Coordination technical reference document. Rather than
establishing a uniform setting threshold of 200 percent of the generator MVA rating at rated
power factor for all applications, the Table 1 setting criteria are based on the maximum expected
generator Real Power output based on whether the generator(s) operates synchronous or
asynchronous.
Phase Time Overcurrent Relay – Voltage-Restrained (51V-R)
Phase time overcurrent voltage-restrained relays (51V-R), which change their sensitivity as a
function of voltage, whether applied for the purpose of primary or backup GSU transformer
protection, for external system phase backup protection, or both, were noted, during analysis of
the August 14, 2003 disturbance event to have unnecessarily or prematurely tripped a number of
generating units or generating plants, contributing to the scope of that disturbance. Specifically,
20 generators are known to have been tripped by voltage-restrained and voltage-controlled
protection functions together. These protective functions are variably referred to by IEEE
function numbers 51V, 51R, 51VR, 51V/R, 51V-R, or other terms. See section 3.10 of the Power
Plant and Transmission System Protection Coordination technical reference document for a
detailed discussion of this protection function.
Phase Time Overcurrent Relay – Voltage Controlled (51V-C)
Phase time overcurrent voltage-controlled relays (51V-C), enabled as a function of voltage, are
variably referred to by IEEE function numbers 51V, 51C, 51VC, 51V/C, 51V-C, or other terms.
See section 3.10 of the Power Plant and Transmission System Protection Coordination technical
reference document for a detailed discussion of this protection function.
Phase Directional Time Overcurrent Relay – Directional Toward Transmission System (67)
See section 3.9.2 of the Power Plant and Transmission System Protection Coordination technical
reference document for a detailed discussion of the phase time overcurrent protection function.
The basis for setting directional and non-directional time overcurrent relays is similar. Note that
the Table 1setting criteria established within the Table 1 options differ from section 3.9.2 of the
Power Plant and Transmission System Protection Coordination technical reference document.
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Rather than establishing a uniform setting threshold of 200 percent of the generator MVA rating
at rated power factor for all applications, the Table 1 setting criteria are based on the maximum
expected generator Real Power output based on whether the generator operates synchronous or
asynchronous.

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Table 1, Options
Introduction
The margins in the Table 1 options are based on guidance found in the Power Plant and
Transmission System Protection Coordination technical reference document. The generator bus
voltage during field-forcing will be higher than the high-side voltage due to the voltage drop
across the GSU transformer. When the relay voltage is supplied from the generator bus, it is
necessary to assess loadability using the generator bus voltage.
Relay Connections
Figures 4 and 5 below illustrate the connections for each of the Table 1 options provided in PRC025-1, Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation Criteria.

Figure 4. Relay Connection for corresponding synchronous options.

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Figure 5. Relay Connection for corresponding asynchronous options including inverter-based
installations.

Synchronous Generators Phase Distance Relay – Directional Toward Transmission System
(21) (Options 1a, 1b, and 1c)
Table 1, Options 1a, 1b, and 1c, are provided for assessing loadability for synchronous
generators applying phase distance relays that are directional toward the Transmission system.
These margins are based on guidance found in section 3.1 of the Power Plant and Transmission
System Protection Coordination technical reference document.
Option 1a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 0.95 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
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times the GSU transformer turns ratio (excluding the impedance). This is the simplest calculation
that approximates the stressed system conditions.
Option 1b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The voltage drop across the GSU transformer
is calculated based on a 0.85 per unit nominal voltage at the high-side terminals of the GSU
transformer(s) and accounts for the turns ratio and impedance. The actual generator bus voltage
may be higher depending on the GSU transformer impedance and the actual Reactive Power
achieved. This calculation is a more involved, more precise setting of the impedance element
than Option 1a.
Option 1c simulates the generator bus voltage coincident with the highest Reactive Power output
achieved during field-forcing in response to a 0.85 per unit nominal voltage on the high-side
terminals of the GSU transformer(s) prior to field-forcing. Using simulation is a more involved,
more precise setting of the impedance element overall.
For Options 1a and 1b, the impedance element is set less than the calculated impedance derived
from 115percent of: the Real Power output of 100 percent of the maximum gross MW capability
reported to the Transmission Planner, and Reactive Power output that equates to 150 percent of
the MW value, derived from the generator nameplate MVA rating at rated power factor.
For Option 1c, the impedance element is set less than the calculated impedance derived from 115
percent of: the Real Power output of 100 percent of the maximum gross MW capability reported
to the Transmission Planner, and Reactive Power output that equates to 100 percent of the
maximum gross Mvar output during field-forcing as determined by simulation.
Synchronous Generators Phase Time Overcurrent Relay – Voltage-Restrained (51V-R)
(Options 2a, 2b, and 2c)
Table 1, Options 2a, 2b, and 2c, are provided for assessing loadability for synchronous
generators applying phase time overcurrent relays which change their sensitivity as a function of
voltage (“voltage-restrained”). These margins are based on guidance found in section 3.10 of the
Power Plant and Transmission System Protection Coordination technical reference document.
Option 2a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 0.95 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is the simplest calculation
that approximates the stressed system conditions.
Option 2b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The voltage drop across the GSU transformer
is calculated based on a 0.85 per unit nominal voltage at the high-side terminals of the GSU
transformer(s) and accounts for the turns ratio and impedance. The actual generator bus voltage
may be higher depending on the GSU transformer impedance and the actual Reactive Power
achieved. This calculation is a more involved, more precise setting of the overcurrent element
than Option 2a.
Option 2c simulates the generator bus voltage coincident with the highest Reactive Power output
achieved during field-forcing in response to a 0.85 per unit nominal voltage on the high-side
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terminals of the GSU transformer(s) prior to field-forcing. Using simulation is a more involved,
more precise setting of the overcurrent element overall.
For Options 2a and 2b, the overcurrent element is set greater than 115 percent of the calculated
current derived from: the Real Power output of 100 percent of the maximum gross MW
capability reported to the Transmission Planner, and Reactive Power output that equates to 150
percent of the MW value, derived from the generator nameplate MVA rating at rated power
factor.
For Option 2c, the overcurrent element is set greater than the calculated current derived from 115
percent of: the Real Power output of 100 percent of the maximum gross MW capability reported
to the Transmission Planner, and Reactive Power output that equates to 100 percent of the
maximum gross Mvar output during field-forcing as determined by simulation.
Synchronous Generators Phase Time Overcurrent Relay – Voltage Controlled (51V-C)
(Option 3)
Table 1, Option 3, is provided for assessing loadability for synchronous generators applying
phase time overcurrent relays which are enabled as a function of voltage (“voltage-controlled”).
These margins are based on guidance found in section 3.10 of the Power Plant and Transmission
System Protection Coordination technical reference document.
Option 3 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 1.0 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is a simple calculation
that approximates the stressed system conditions.
For Option 3, the voltage control setting is set less than 75 percent of the calculated generator
bus voltage. The voltage setting must be set such that the function (e.g., 51V-C) will not trip
under extreme emergency conditions as the time overcurrent function will be set less than
generator full load current (e.g. rated armature current). Relays enabled as a function of voltage
are indifferent as to the current setting, and this option simply requires that the relays not respond
for the depressed voltage.
Asynchronous Generators Phase Distance Relay – Directional Toward Transmission
System (21) (Option 4)
Table 1, Option 4 is provided for assessing loadability for asynchronous generators applying
phase distance relays that are directional toward the Transmission system. These margins are
based on guidance found in section 3.1 of the Power Plant and Transmission System Protection
Coordination technical reference document.
Option 4 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 1.0 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is a simple calculation
that approximates the stressed system conditions.

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Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability
using the generator-side voltage. Asynchronous generators do not produce as much Reactive
Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU
transformer is not as significant. Therefore, the generator bus voltage can be conservatively
estimated by reflecting the high-side nominal voltage to the generator-side based on the GSU
transformer’s turns ratio.
For Option 4, the impedance element is set less than the calculated impedance derived from 130
percent of the maximum aggregate nameplate MVA output at rated power factor including the
Mvar output of any static or dynamic Reactive Power devices. This is determined by summing
the total MW and Mvar capability of the generation equipment behind the relay and any static or
dynamic Reactive Power devices that contribute to the power flow through the relay.
Asynchronous Generators Phase Time Overcurrent Relay – Voltage-Restrained (51V-R)
(Option 5)
Table 1, Option 5 is provided for assessing loadability for asynchronous generators applying
phase time overcurrent relays which change their sensitivity as a function of voltage (“voltagerestrained”). These margins are based on guidance found in section 3.10 of the Power Plant and
Transmission System Protection Coordination technical reference document.
Option 5 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 1.0 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is a simple calculation
that approximates the stressed system conditions.
Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability
using the generator-side voltage. Asynchronous generators do not produce as much Reactive
Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU
transformer is not as significant. Therefore, the generator bus voltage can be conservatively
estimated by reflecting the high-side nominal voltage to the generator-side based on the GSU
transformer’s turns ratio.
For Option 5, the overcurrent element is set greater than 130 percent of the calculated current
derived from the maximum aggregate nameplate MVA output at rated power factor including the
Mvar output of any static or dynamic Reactive Power devices. This is determined by summing
the total MW and Mvar capability of the generation equipment behind the relay and any static or
dynamic Reactive Power devices that contribute to the power flow through the relay.
Asynchronous Generator Phase Time Overcurrent Relays – Voltage Controlled (51V-C)
(Option 6)
Table 1, Option 6, is provided for assessing loadability for asynchronous generators applying
phase time overcurrent relays which are enabled as a function of voltage (“voltage-controlled”).
These margins are based on guidance found in section 3.10 of the Power Plant and Transmission
System Protection Coordination technical reference document.

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Option 6 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 1.0 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is a simple calculation
that approximates the stressed system conditions.
For Option 6, the voltage control setting is set less than 75 percent of the calculated generator
bus voltage. The voltage setting must be set such that the function (e.g., 51V-C) will not trip
under extreme emergency conditions as the time overcurrent function will be set less than
generator full load current (e.g. rated armature current). Relays enabled as a function of voltage
are indifferent as to the current setting, and this option simply requires that the relays not respond
for the depressed voltage.
Generator Step-up Transformer (Synchronous Generators) Phase Distance Relays –
Directional Toward Transmission System (21) (Options 7a, 7b, and 7c)
The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs
that NERC address relay loadability for protective relays applied on GSU transformers. These
margins are based on guidance found in section 3.1 of the Power Plant and Transmission System
Protection Coordination technical reference document.
Table 1, Options 7a, 7b, and 7c, are provided for assessing loadability for GSU transformers
applying phase distance relays that are directional toward the Transmission system on
synchronous generators that are connected to the generator-side of the GSU transformer of a
synchronous generator. Where the relay is connected on the high-side of the GSU transformer,
use Option 14.
Option 7a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 0.95 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is the simplest calculation
that approximates the stressed system conditions.
Option 7b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The voltage drop across the GSU transformer
is calculated based on a 0.85 per unit nominal voltage at the high-side terminals of the GSU
transformer(s) and accounts for the turns ratio and impedance. The actual generator bus voltage
may be higher depending on the GSU transformer impedance and the actual Reactive Power
achieved. This calculation is a more involved, more precise setting of the impedance element
than Option 7a.
Option 7c simulates the generator bus voltage coincident with the highest Reactive Power output
achieved during field-forcing in response to a 0.85 per unit nominal voltage on the high-side
terminals of the GSU transformer(s) prior to field-forcing. Using simulation is a more involved,
more precise setting of the overcurrent element overall.
For Options 7a and 7b the impedance element is set less than the calculated impedance derived
from 115 percent of: the Real Power output of 100 percent of the aggregate generation MW
capability reported to the Transmission Planner, and Reactive Power output that equates to 150

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percent of the aggregate generation MW value, derived from the generator nameplate MVA
rating at rated power factor.
For Option 7c, the impedance element is set less than the calculated impedance derived from 115
percent of: the Real Power output of 100 percent of the aggregate generation MW capability
reported to the Transmission Planner, and Reactive Power output that equates to 100 percent of
the maximum gross Mvar output during field-forcing as determined by simulation.
Generator Step-up Transformer (Synchronous Generators) Phase Time Overcurrent Relay
(51) (Options 8a, 8b and 8c)
The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs
that NERC address relay loadability for protective relays applied on GSU transformers. Note that
the setting criteria established within these options differ from section 3.9.2 of the Power Plant
and Transmission System Protection Coordination technical reference document. Rather than
establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at
rated power factor for all applications, the setting criteria are based on the maximum expected
generator output.
Table 1, Options 8a, 8b, and 8c, are provided for assessing loadability for GSU transformers
applying phase time overcurrent relays on synchronous generators that are connected to the
generator-side of the GSU transformer of a synchronous generator. Where the relay is connected
on the high-side of the GSU transformer, use Option 15.
Option 8a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 0.95 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is the simplest calculation
that approximates the stressed system conditions.
Option 8b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The voltage drop across the GSU transformer
is calculated based on a 0.85 per unit nominal voltage at the high-side terminals of the GSU
transformer(s) and accounts for the turns ratio and impedance. The actual generator bus voltage
may be higher depending on the GSU transformer impedance and the actual Reactive Power
achieved. This calculation is a more involved, more precise setting of the impedance element
than Option 8a.
Option 8c simulates the generator bus voltage coincident with the highest Reactive Power output
achieved during field-forcing in response to a 0.85 per unit nominal voltage on the high-side
terminals of the GSU transformer(s) prior to field-forcing. Using simulation is a more involved,
more precise setting of the overcurrent element overall.
For Options 8a and 8b, the overcurrent element is set greater than 115 percent of the calculated
current derived from: the Real Power output of 100 percent of the aggregate generation MW
capability reported to the Transmission Planner, and Reactive Power output that equates to 150
percent of the aggregate generation MW value, derived from the generator nameplate MVA
rating at rated power factor.

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For Option 8c, the overcurrent element is set greater than 115 percent of the calculated current
derived from: the Real Power output of 100 percent of the aggregate generation MW capability
reported to the Transmission Planner, and Reactive Power output that equates to 100 percent of
the maximum gross Mvar output during field-forcing as determined by simulation.
Generator Step-up Transformer (Synchronous Generators) Phase Directional Time
Overcurrent Relay – Directional Toward Transmission System (67) (Options 9a, 9b and 9c)
The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs
that NERC address relay loadability for protective relays applied on GSU transformers. Note that
the setting criteria established within these options differ from section 3.9.2 of the Power Plant
and Transmission System Protection Coordination technical reference document. Rather than
establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at
rated power factor for all applications, the setting criteria are based on the maximum expected
generator output.
Table 1, Options 9a, 9b, and 9c, are provided for assessing loadability for GSU transformers
applying phase directional time overcurrent relays directional toward the Transmission System
that are connected to the generator-side of the GSU transformer of a synchronous generator.
Where the relay is connected on the high-side of the GSU transformer, use Option 16.
Option 9a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 0.95 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is the simplest calculation
that approximates the stressed system conditions.
Option 9b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The voltage drop across the GSU transformer
is calculated based on a 0.85 per unit nominal voltage at the high-side terminals of the GSU
transformer(s) and accounts for the turns ratio and impedance. The actual generator bus voltage
may be higher depending on the GSU transformer impedance and the actual Reactive Power
achieved. This calculation is a more involved, more precise setting of the impedance element
than Option 9a.
Option 9c simulates the generator bus voltage coincident with the highest Reactive Power output
achieved during field-forcing in response to a 0.85 per unit nominal voltage on the high-side
terminals of the GSU transformer(s) prior to field-forcing. Using simulation is a more involved,
more precise setting of the overcurrent element overall.
For Options 9a and 9b, the overcurrent element is set greater than 115 percent of the calculated
current derived from: the Real Power output of 100 percent of the aggregate generation MW
capability reported to the Transmission Planner, and Reactive Power output that equates to 150
percent of the aggregate generation MW value, derived from the generator nameplate MVA
rating at rated power factor.
For Option 9c, the overcurrent element is set greater than 115 percent of the calculated current
derived from: the Real Power output of 100 percent of the aggregate generation MW capability
reported to the Transmission Planner, and Reactive Power output that equates to 100 percent of
the maximum gross Mvar output during field-forcing as determined by simulation.
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Generator Step-up Transformer (Asynchronous Generators) Phase Distance Relay –
Directional Toward Transmission System (21) (Option 10)
The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs
that NERC address relay loadability for protective relays applied on GSU transformers. Table 1,
Option 10 is provided for assessing loadability for GSU transformers applying phase distance
relays that are directional toward the Transmission System that are connected to the generatorside of the GSU transformer of an asynchronous generator. These margins are based on guidance
found in section 3.1 of the Power Plant and Transmission System Protection Coordination
technical reference document. Where the relay is connected on the high-side of the GSU
transformer, use Option 17.
Option 10 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 1.0 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is a simple calculation
that approximates the stressed system conditions.
Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability
using the generator-side voltage. Asynchronous generators do not produce as much Reactive
Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU
transformer is not as significant. Therefore, the generator bus voltage can be conservatively
estimated by reflecting the high-side nominal voltage to the generator-side based on the GSU
transformer’s turns ratio.
For Option 10, the impedance element is set less than the calculated impedance, derived from
130 percent of the maximum aggregate nameplate MVA output at rated power factor including
the Mvar output of any static or dynamic Reactive Power devices. This is determined by
summing the total MW and Mvar capability of the generation equipment behind the relay and
any static or dynamic Reactive Power devices that contribute to the power flow through the
relay.
Generator Step-up Transformer (Asynchronous Generators) Phase Time Overcurrent
Relay (51) (Option 11)
The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs
that NERC address relay loadability for protective relays applied on GSU transformers. Note that
the setting criteria established within these options differ from section 3.9.2 of the Power Plant
and Transmission System Protection Coordination technical reference document. Rather than
establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at
rated power factor for all applications, the setting criteria are based on the maximum expected
generator output.
Table 1, Option 11 is provided for assessing loadability for GSU transformers applying phase
time overcurrent relays on asynchronous generators that are connected to the generator-side of
the GSU transformer. Where the relay is connected on the high-side of the GSU transformer, use
Option 18.

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Option 11 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 1.0 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is a simple calculation
that approximates the stressed system conditions.
Since the relay current is supplied from the generator bus, it is necessary to assess loadability
using the generator-side voltage. Asynchronous generators do not produce as much Reactive
Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU
transformer is not as significant. Therefore, the generator bus voltage can be conservatively
estimated by reflecting the high-side nominal voltage to the generator-side based on the GSU
transformer’s turns ratio.
For Option 11, the overcurrent element is set greater than 130 percent of the calculated current
derived from the maximum aggregate nameplate MVA output at rated power factor including the
Mvar output of any static or dynamic Reactive Power devices. This is determined by summing
the total MW and Mvar capability of the generation equipment behind the relay and any static or
dynamic Reactive Power devices that contribute to the power flow through the relay.
Generator Step-up Transformer (Asynchronous Generators) Phase Directional Time
Overcurrent Relay – Directional Toward Transmission System (67) (Option 12)
The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs
that NERC address relay loadability for protective relays applied on GSU transformers. Note that
the setting criteria established within these options differ from section 3.9.2 of the Power Plant
and Transmission System Protection Coordination technical reference document. Rather than
establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at
rated power factor for all applications, the setting criteria are based on the maximum expected
generator output.
Table 1, Option 12 is provided for assessing loadability for GSU transformers applying phase
directional time overcurrent relays directional toward the Transmission System on asynchronous
generators that are connected to the generator-side of the GSU transformer of an asynchronous
generator. Where the relay is connected on the high-side of the GSU transformer, use Option 19.
Option 12 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on
the high-side terminals of the GSU transformer(s). The generator bus voltage is calculated by
multiplying a 1.0 per unit nominal voltage at the high-side terminals of the GSU transformer(s)
times the GSU transformer turns ratio (excluding the impedance). This is a simple calculation
that approximates the stressed system conditions.
Since the relay current is supplied from the generator bus, it is necessary to assess loadability
using the generator-side voltage. Asynchronous generators do not produce as much Reactive
Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU
transformer is not as significant. Therefore, the generator bus voltage can be conservatively
estimated by reflecting the high-side nominal voltage to the generator-side based on the GSU
transformer’s turns ratio.
For Option 12, the overcurrent element is set greater than 130 percent of the calculated current
derived from the maximum aggregate nameplate MVA output at rated power factor including the
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Mvar output of any static or dynamic Reactive Power devices. This is determined by summing
the total MW and Mvar capability of the generation equipment behind the relay and any static or
dynamic Reactive Power devices that contribute to the power flow through the relay.
Unit Auxiliary Transformers Phase Time Overcurrent Relay (51) (Options 13a and 13b)
In FERC Order No. 733, paragraph 104, directs NERC to include in this standard a loadability
requirement for relays used for overload protection of the UAT that supply normal station
service for a generating unit. For the purposes of this standard, UATs provide the overall station
power to support the unit at its maximum gross operation.
Table 1, Options 13a and 13b provide two options for addressing phase time overcurrent relaying
applied at the high-side of UATs. The transformer high-side winding may be directly connected
to the transmission grid or at the generator isolated phase bus (IPB) or iso-phase bus. Phase time
overcurrent relays applied at the high-side of the UAT that remove the transformer from service
resulting in an immediate (e.g., via lockout or auxiliary tripping relay operation) operation of the
relays will cause the associated generator to trip of the associated generator are to be compliant
with the relay setting criteria in this standard. Due to the complexity of the application of lowside overload relays for single or multi-winding transformers, phase time overcurrent relaying
applied to the low voltage terminals of the UAT are not addressed in this standard. Although the
UAT is not directly in the output path from the generator to the Transmission system, it is an
essential component for operation of the generating unit or plant.

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Refer to the Figures 6 and 7 below for example configurations:

Figure-6 – Auxiliary Power System (independent from generator).

Unit Auxiliary
Transformer

Transformer
Covered by this
standard

GSU
Station
Loads

System

Figure-7 – Typical auxiliary power system for generation units or plants.
The UATs supplying power to the unit or plant electrical auxiliaries are sized to accommodate
the maximum expected overall UAT load demand at the highest generator output. Although the
transformer nameplate MVA size normally includes capacity for future loads as well as capacity

48 of 99

PRC-025-1— Application Guidelines

for starting of large induction motors on the original unit or plant design, the nameplate MVA
capacity of the transformer may be near full load.
Because of the various design and loading characteristics of UATs, two options (i.e., 13a and
13b) are provided to accommodate an entity’s protection philosophy while preventing the UAT
transformer phase time overcurrent relays from operating during the dynamic conditions
anticipated by this standard.
Options 13a and 13b are based on the transformer bus voltage corresponding to 1.0 per unit
nominal voltage on the high-side winding of the UAT.
For Option 13a, the overcurrent element shall be set greater than 150 percent of the calculated
current derived from the UAT maximum nameplate MVA rating. This is a simple calculation
that approximates the stressed system conditions.
For Option 13b, the overcurrent element shall be set greater than 150 percent of the UAT
measured current at the generator maximum gross MW capability reported to the Transmission
Planner. This allows for a reduced setting pickup compared to Option 13a and the entity’s relay
setting philosophy. This is a more involved calculation that approximates the stressed system
conditions by allowing the entity to consider the actual load placed on the UAT based on the
generator’s maximum gross MW capability reported to the Transmission Planner.
The performance of the UAT loads during stressed system conditions (i.e., depressed voltages) is
very difficult to determine. Rather than requiring responsible entities to determine the response
of UAT loads to depressed voltage, the technical experts writing the standard elected to increase
the margin to 150 percent from that used elsewhere in this standard (e.g., 115 percent) and use a
generator bus voltage of 1.0 per unit. A minimum pickup current based on 150 percent of
maximum transformer nameplate MVA rating at 1.0 per unit generator bus voltage will provide
adequate transformer protection based on IEEE C37.91 at full load conditions while providing
sufficient relay loadability to prevent a trip of the UAT, and subsequent unit trip, due to
increased UAT load current during stressed system voltage conditions. Even if the UAT is
equipped with an automatic tap changer, the tap changer may not respond quickly enough for the
conditions anticipated within this standard, and thus shall not be used to reduce this margin.
Elements that connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or generating plant.
Elements may also supply generating plant loads. (Synchronous Generators) Phase
Distance Relays – Directional Toward Transmission System (21) (Options 14a and 14b)
Relays applied on Elements that connect the GSU transformer(s) to the Transmission system that
are used exclusively to export energy directly from a BES generating unit or generating plant
(Elements may also supply generating plant loads.) are challenged by loading conditions similar
to relays applied on generators and GSU transformers. These margins are based on guidance
found in section 3.1 of the Power Plant and Transmission System Protection Coordination
technical reference document. Relays applied on the high-side of the GSU transformer respond
to the same quantities as the relays connected on the Elements that connect the GSU
transformer(s) to the Transmission system that are used exclusively to export energy directly
from a BES generating unit or generating plant (Elements may also supply generating plant
loads.), thus Option 14 is used for these relays as well.
49 of 99

PRC-025-1— Application Guidelines

Table 1, Options 14a and 14b, establish criteria for phase distance relays directional toward the
Transmission system to prevent Elements that connect the GSU transformer(s) to the
Transmission system that are used exclusively to export energy directly from a BES generating
unit or generating plant (Elements may also supply generating plant loads.) from operating
during the dynamic conditions anticipated by this standard. The stressed system conditions,
anticipated by Option 14a reflects a 0.85 per unit Transmission system voltage; therefore,
establishing that the impedance value used for applying the Elements that connect the GSU
transformer(s) to the Transmission system that are used exclusively to export energy directly
from a BES generating unit or generating plant (Elements may also supply generating plant
loads.) phase distance relays that are directional toward the Transmission system be calculated
from the apparent power addressed within the criteria, with application of a 0.85 per unit
Transmission system voltage. Consideration of the voltage drop across the GSU transformer is
not necessary. Option 14b simulates the line voltage coincident with the highest Reactive Power
output achieved during field-forcing in response to a 0.85 per unit nominal voltage on the highside terminals of the GSU transformer(s) prior to field-forcing. Using simulation is a more
involved, more precise setting of the overcurrent element overall.
For Option 14a, the impedance element is set less than the calculated impedance derived from
115 percent of: the Real Power output of 100 percent of the aggregate generation MW capability
reported to the Transmission Planner, and Reactive Power output that equates to 120 percent of
the aggregate generation MW value, derived from the generator nameplate MVA rating at rated
power factor. This Reactive Power value differs from the 150 percent multiplier used in other
application to account for the Reactive Power losses in the GSU transformer. This is a simple
calculation that approximates the stressed system conditions.
For Option 14b, the impedance element is set less than the calculated impedance derived from
115 percent of: the Real Power output of 100 percent of the aggregate generation MW capability
reported to the Transmission Planner, and Reactive Power output that equates to 100 percent of
the maximum gross Mvar output during field-forcing as determined by simulation. Using
simulation is a more involved, more precise setting of the impedance element overall.
Elements that connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or generating plant.
Elements may also supply generating plant loads.(Synchronous Generators) Phase
overcurrent supervisory element (50) – associated with current-based, communicationassisted schemes where the scheme is capable of tripping for loss of communications
installed on the high-side of the GSU transformer or Phase Time Overcurrent Relay (51)
(Options 15a and 15b)
Relays applied on Elements that connect the GSU transformer(s) to the Transmission system that
are used exclusively to export energy directly from a BES generating unit or generating plant
(Elements may also supply generating plant loads.) are challenged by loading conditions similar
to relays applied on generators and GSU transformers. Note that the setting criteria established
within these options differ from section 3.9.2 of the Power Plant and Transmission System
Protection Coordination technical reference document. Rather than establishing a uniform setting
threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all
applications, the setting criteria are based on the maximum expected generator output. Relays
50 of 99

PRC-025-1— Application Guidelines

applied on the high-side of the GSU transformer respond to the same quantities as the relays
connected on the Elements that connect the GSU transformer(s) to the Transmission system that
are used exclusively to export energy directly from a BES generating unit or generating plant
(Elements may also supply generating plant loads.), thus Option 15 is used for these relays as
well.
Table 1, Options 15a and 15b, establish criteria for phase time overcurrent relays to prevent
Elements that connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or generating plant (Elements
may also supply generating plant loads.) from operating during the dynamic conditions
anticipated by this standard. The stressed system conditions, anticipated by Option 15a reflects a
0.85 per unit Transmission system voltage; therefore, establishing that the current value used for
applying the Elements that connect the GSU transformer(s) to the Transmission system that are
used exclusively to export energy directly from a BES generating unit or generating plant
(Elements may also supply generating plant loads.) phase time overcurrent relays be calculated
from the apparent power addressed within the criteria, with application of a 0.85 per unit
Transmission system voltage. Consideration of the voltage drop across the GSU transformer is
not necessary. Option 15b simulates the line voltage coincident with the highest Reactive Power
output achieved during field-forcing in response to a 0.85 per unit nominal voltage on the highside terminals of the GSU transformer(s) prior to field-forcing. Using simulation is a more
involved, more precise setting of the overcurrent element overall.
For Option 15a, the overcurrent element is set greater than 115 percent of the calculated current
derived from: the Real Power output of 100 percent of the aggregate generation MW capability
reported to the Transmission Planner, and Reactive Power output that equates to 120 percent of
the aggregate generation MW value, derived from the generator nameplate MVA rating at rated
power factor. This Reactive Power value differs from the 150 percent multiplier used in other
application to account for the Reactive Power losses in the GSU transformer. This is a simple
calculation that approximates the stressed system conditions.
For Option 15b, the overcurrent element is set greater than 115 percent of the calculated current
derived from: the Real Power output of 100 percent of the aggregate generation MW capability
reported to the Transmission Planner, and Reactive Power output that equates to 100 percent of
the maximum gross Mvar output during field-forcing as determined by simulation. Using
simulation is a more involved, more precise setting of the overcurrent element overall.
Elements that connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or generating plant.
Elements may also supply generating plant loads.(Synchronous Generators) Phase
Directional Time Overcurrent Relay – Directional Toward Transmission System (67)
(Options 16a and 16b)
Relays applied on Elements that connect the GSU transformer(s) to the Transmission system that
are used exclusively to export energy directly from a BES generating unit or generating plant
(Elements may also supply generating plant loads.) are challenged by loading conditions similar
to relays applied on generators and GSU transformers. Note that the setting criteria established
within these options differ from section 3.9.2 of the Power Plant and Transmission System
Protection Coordination technical reference document. Rather than establishing a uniform setting
51 of 99

PRC-025-1— Application Guidelines

threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all
applications, the setting criteria are based on the maximum expected generator output. Relays
applied on the high-side of the GSU transformer respond to the same quantities as the relays
connected on the Elements that connect the GSU transformer(s) to the Transmission system that
are used exclusively to export energy directly from a BES generating unit or generating plant
(Elements may also supply generating plant loads.), thus Option 16 is used for these relays as
well.
Table 1, Options 16a and 16b, establish criteria for phase directional time overcurrent relays that
are directional toward the Transmission system to prevent Elements that connect the GSU
transformer(s) to the Transmission system that are used exclusively to export energy directly
from a BES generating unit or generating plant (Elements may also supply generating plant
loads.) from operating during the dynamic conditions anticipated by this standard. The stressed
system conditions, anticipated by Option 16a reflects a 0.85 per unit Transmission system
voltage; therefore, establishing that the current value used for applying the interconnection
Facilities phase directional time overcurrent relays be calculated from the apparent power
addressed within the criteria, with application of a 0.85 per unit Transmission system voltage.
Consideration of the voltage drop across the GSU transformer is not necessary. Option 16b
simulates the line voltage coincident with the highest Reactive Power output achieved during
field-forcing in response to a 0.85 per unit nominal voltage on the high-side terminals of the
GSU transformer(s) prior to field-forcing. Using simulation is a more involved, more precise
setting of the overcurrent element overall.
For Option 16a, the overcurrent element is set greater than 115 percent of the calculated current
derived from: the Real Power output of 100 percent of the aggregate generation MW capability
reported to the Transmission Planner, and Reactive Power output that equates to 120 percent of
the aggregate generation MW value, derived from the generator nameplate MVA rating at rated
power factor. This Reactive Power value differs from the 150 percent multiplier used in other
application to account for the Reactive Power losses in the GSU transformer. This is a simple
calculation that approximates the stressed system conditions.
For Option 16b, the overcurrent element is set greater than 115 percent of the calculated current
derived from: the Real Power output of 100 percent of the aggregate generation MW capability
reported to the Transmission Planner, and Reactive Power output that equates to 100 percent of
the maximum gross Mvar output during field-forcing as determined by simulation. Using
simulation is a more involved, more precise setting of the overcurrent element overall.
Elements that connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or generating plant.
Elements may also supply generating plant loads. (Asynchronous Generators) Phase
overcurrent supervisory element (50) – associated with current-based, communicationassisted schemes where the scheme is capable of tripping for loss of communications
installed on the high-side of the GSU transformer or Phase Distance Relay – Directional
Toward Transmission System (21) (Option 17)
Relays applied on Elements that connect the GSU transformer(s) to the Transmission system that
are used exclusively to export energy directly from a BES generating unit or generating plant
(Elements may also supply generating plant loads.) are challenged by loading conditions similar
52 of 99

PRC-025-1— Application Guidelines

to relays applied on generators and GSU transformers. These margins are based on guidance
found in section 3.1 of the Power Plant and Transmission System Protection Coordination
technical reference document.
Table 1, Option 17 establishes criteria for phase distance relays that are directional toward the
Transmission system to prevent Elements that connect the GSU transformer(s) to the
Transmission system that are used exclusively to export energy directly from a BES generating
unit or generating plant (Elements may also supply generating plant loads.) from operating
during the dynamic conditions anticipated by this standard. Option 17 applies a 1.0 per unit
nominal voltage on the high-side terminals of the GSU transformer(s) to calculate the impedance
from the maximum aggregate nameplate MVA. Asynchronous generators do not produce as
much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow
through the GSU transformer is not as significant.
For Option 17, the impedance element is set less than the calculated impedance derived from 130
percent of the maximum aggregate nameplate MVA output at rated power factor including the
Mvar output of any static or dynamic Reactive Power devices. This is determined by summing
the total MW and Mvar capability of the generation equipment behind the relay and any static or
dynamic Reactive Power devices that contribute to the power flow through the relay. This is a
simple calculation that approximates the stressed system conditions.
Elements that connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or generating plant.
Elements may also supply generating plant loads. (Asynchronous Generators) Phase Time
Overcurrent Relay (51) (Option 18)
Relays applied on Elements that connect the GSU transformer(s) to the Transmission system that
are used exclusively to export energy directly from a BES generating unit or generating plant
(Elements may also supply generating plant loads.) are challenged by loading conditions similar
to relays applied on generators and GSU transformers. Note that the setting criteria established
within these options differ from section 3.9.2 of the Power Plant and Transmission System
Protection Coordination technical reference document. Rather than establishing a uniform setting
threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all
applications, the setting criteria are based on the maximum expected generator output.
Table 1, Option 18 establishes criteria for phase time overcurrent relays to prevent Elements that
connect the GSU transformer(s) to the Transmission system that are used exclusively to export
energy directly from a BES generating unit or generating plant (Elements may also supply
generating plant loads.) from operating during the dynamic conditions anticipated by this
standard. Option 18 applies a 1.0 per unit nominal voltage on the high-side terminals of the GSU
transformer(s) to calculate the current from the maximum aggregate nameplate MVA.
Asynchronous generators do not produce as much Reactive Power as synchronous generators;
the voltage drop due to Reactive Power flow through the GSU transformer is not as significant.
For Option 18, the overcurrent element is set greater than 130 percent of the calculated current
derived from the maximum aggregate nameplate MVA output at rated power factor including the
Mvar output of any static or dynamic Reactive Power devices. This is determined by summing
the total MW and Mvar capability of the generation equipment behind the relay and any static or
53 of 99

PRC-025-1— Application Guidelines

dynamic Reactive Power devices that contribute to the power flow through the relay. This is a
simple calculation that approximates the stressed system conditions.
Elements that connect the GSU transformer(s) to the Transmission system that are used
exclusively to export energy directly from a BES generating unit or generating plant.
Elements may also supply generating plant loads. (Asynchronous Generators) Phase
Directional Time Overcurrent Relay – Directional Toward Transmission System (67)
(Option 19)
Relays applied on Elements that connect the GSU transformer(s) to the Transmission system that
are used exclusively to export energy directly from a BES generating unit or generating plant
(Elements may also supply generating plant loads.) are challenged by loading conditions similar
to relays applied on generators and GSU transformers. Note that the setting criteria established
within these options differ from section 3.9.2 of the Power Plant and Transmission System
Protection Coordination technical reference document. Rather than establishing a uniform setting
threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all
applications, the setting criteria are based on the maximum expected generator output.
Table 1, Option 19 establishes criteria for phase directional time overcurrent relays that are
directional toward the Transmission system to prevent Elements that connect the GSU
transformer(s) to the Transmission system that are used exclusively to export energy directly
from a BES generating unit or generating plant (Elements may also supply generating plant
loads.) from operating during the dynamic conditions anticipated by this standard. Option 19
applies a 1.0 per unit nominal voltage on the high-side terminals of the GSU transformer(s) to
calculate the current from the maximum aggregate nameplate MVA. Asynchronous generators
do not produce as much Reactive Power as synchronous generators; the voltage drop due to
Reactive Power flow through the GSU transformer is not as significant.
For Option 19, the overcurrent element is set greater than 130 percent of the calculated current
derived from the maximum aggregate nameplate MVA output at rated power factor including the
Mvar output of any static or dynamic Reactive Power devices. This is determined by summing
the total MW and Mvar capability of the generation equipment behind the relay and any static or
dynamic Reactive Power devices that contribute to the power flow through the relay. This is a
simple calculation that approximates the stressed system conditions.

54 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations
Introduction
Example Calculations.
Input Descriptions

Input Values

Synchronous Generator nameplate (MVA @ rated pf):

903
0.85

Generator rated voltage (Line-to-Line):

_ 22

Real Power output in MW as reported to the TP:

!_"
"# 700.0 %

Generator step-up (GSU) transformer rating:

&' 903

GSU transformer reactance (903 MVA base):

(&' 12.14%

GSU transformer MVA base:

,
- 767.6

GSU transformer turns ratio:

/0"
1

High-side nominal system voltage (Line-to-Line):

345

Current transformer (CT) ratio:

23"
1

Potential transformer (PT) ratio low-side:

!3"
1

PT ratio high-side:

!3"
1_4

Unit auxiliary transformer (UAT) nameplate:

UAT low-side voltage:

'56 13.8

UAT CT ratio:

23'56

CT high voltage ratio:

23"
1_4

Reactive Power output of static reactive device:

7-
1 15 89:

22
346.5

25000
5
200
1

2000
1

5000
5

2000
5

Reactive Power output of static reactive device generation:

7_-
1 5 89:

Asynchronous generator nameplate (MVA @ rated pf):

5-_

55 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations.
0.85

5000
5

Asynchronous CT ratio:

235-_"
1

Asynchronous high voltage CT ratio:

235-_"
1_4

300
5

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PRC-025-1— Generator Relay Loadability

Example Calculations: Option 1a
Option 1a represents the simplest calculation for synchronous generators applying a phase distance relay (21)
directional toward the Transmission system.
Real Power output (P):
Eq. (1)

! _

;
! 903 ; 0.85
! 767.6 %

Reactive Power output (Q):
Eq. (2)

< 150% ; !

< 1.50 ; 767.6 %
< 1151.3 89:

Option 1a, Table 1 – Bus Voltage, calls for a 0.95 per unit of the high-side nominal voltage for the generator bus
voltage (Vgen):
Eq. (3)

0.95 . =.; ; /0"
1
0.95 ; 345 ; >
20.81

22
?
346.5

Apparent power (S):
Eq. (4)

/ !_"
"# @ A<

/ 700.0 % @ A1151.3 89:
/ 1347.4∠58.7°
Primary impedance (Zpri):
Eq. (5)

C
"1
C
"1

F20.81 GD
1347.4∠ H 58.7°

C
"1 0.321∠58.7° Ω
Secondary impedance (Zsec):
Eq. (6)

C- C
"1 ;

23"
1
!3"
1
57 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 1a
C- 0.321∠58.7° Ω ;

DIJJJ
I
DJJ
K

C- 0.321∠58.7° Ω ; 25
C- 8.035∠58.7° Ω

To satisfy the 115% margin in Option 1a:
Eq. (7)

CLMN 11
CLMN 11

C-
115%

8.035∠58.7° Ω
1.15

CLMN 11 6.9873∠58.7° Ω
O"
-1
#
58.7°

Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚, then the maximum
allowable impedance reach is:
Eq. (8)

C
P Q
C
P Q
C
P Q

|CLMN 11 |

cosVOW65 H O"
-1
#
X
6.9873 Ω
cosF85.0° H 58.7°G
6.9873 Ω
0.896

C
P Q 7.793∠85.0° Ω

Example Calculations: Options 1b and 7b
Option 1b represents a more complex, more precise calculation for synchronous generators applying a phase
distance relay (21) directional toward the Transmission system. This option requires calculating low-side voltage
taking into account voltage drop across the GSU transformer. Similarly these calculations may be applied to Option
7b for GSU transformers applying a phase distance relay (21) directional toward the Transmission system.
Real Power output (P):
Eq. (9)

! _

;
! 903 ; 0.85
! 767.6 %

58 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 1b and 7b
Reactive Power output (Q):
Eq. (10)

< 150% ; !

< 1.50 ; 767.6 %
< 1151.3 89:

Convert Real Power, Reactive Power, and transformer reactance to per unit values on a 767.6 MVA base (MVAbase):
Real Power output (P):
Eq. (11)

!
Y
!
Y

!_"
"#
,
-
700.0 %
767.6

!
Y 0.91 . =.
Reactive Power output (Q):
Eq. (12)

<
Y
<
Y

<
,
-

1151.3 89:
767.6

<
Y 1.5 . =.

Transformer impedance (Xpu):
Eq. (13)

(
Y (&'F#G ; >
(
Y 12.14% ; >
(
Y 0.1032 . =.

,
-
?
&'

767.6
?
903

Using the formula below; calculate the low-side GSU transformer voltage (Vlow-side) using 0.85 p.u. high-side voltage
(Vhigh-side). Estimate initial low-side voltage to be 0.95 p.u. and repeat the calculation as necessary until Vlow-side
converges. A convergence of less than one percent (<1%) between iterations is considered sufficient:
Eq. (14)

OZ[-1# sin[K ^
OZ[-1# sin[K ^

V!
Y ; _(
Y _X
b
V|Z[-1# | ; `1[-1# aX
F0.91 ; 0.1032G
b
F0.95 ; 0.85G

59 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 1b and 7b
OZ[-1# 6.7°
Eq. (15)

|Z[-1# |
|Z[-1# |
|Z[-1# |
|Z[-1# |

_1[-1# _ ; cosFOZ[-1# G c d_1[-1# _ ; cos D FOZ[-1# G @ 4 ; <
Y ; (
Y
2

|0.85| ; cosF6.7°G c e|0.85|D ; cos D F6.7°G @ 4 ; 1.5 ; 0.1032
2
|0.85| ; 0.9931 c √0.7225 ; 0.9864 @ 0.6192
2
0.8441 c 1.1541
2

|Z[-1# | 0.9991 . =.

Use the new estimated Vlow-side value of 0.9991 per unit for the second iteration:
Eq. (16)

OZ[-1# sin[K ^
OZ[-1# sin[K ^
OZ[-1# 6.3°

Eq. (17)

|Z[-1# |
|Z[-1# |
|Z[-1# |
|Z[-1# |

V!
Y ; _(
Y _X

b
V|Z[-1# | ; `1[-1# aX
F0.91 ; 0.1032G
b
F0.9991 ; 0.85G

_1[-1# _ ; cosFOZ[-1# G c d_1[-1# _ ; cos D FOZ[-1# G @ 4 ; <
Y ; (
Y
2

|0.85| ; cosF6.3°G c e|0.85|D ; cos D F6.3°G @ 4 ; 1.5 ; 0.1032
2
|0.85| ; 0.9940 c √0.7225 ; 0.9880 @ 0.6192
2
0.8449 c 1.1546
2

|Z[-1# | 0.9998 . =.

To account for system high-side nominal voltage and the transformer tap ratio:
Eq. (18)

,Y- |Z[-1# | ; ; /0"
1
,Y- 0.9998 . =.; 345 ; >
,Y- 21.90

22
?
346.5

60 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 1b and 7b
Apparent power (S):
Eq. (19)

/ !_"
"# @ A<

/ 700.0 % @ A1151.3 89:
/ 1347.4∠58.7° MVA
Primary impedance (Zpri):
Eq. (20)

C
"1
C
"1

D
,Y/E

F21.90 GD
1347.4∠ H 58.7°

C
"1 0.356∠58.7° Ω
Secondary impedance (Zsec):
Eq. (21)

C- C
"1 ;

23"
1
!3"
1

C- 0.356∠58.7° Ω ;

DIJJJ
I
DJJ
K

C- 0.356∠58.7° Ω ; 25
C- 8.900∠58.7° Ω

To satisfy the 115% margin in Options 1b and 7b:
Eq. (22)

CLMN 11
CLMN 11

C-
115%

8.900∠58.7° Ω
1.15

CLMN 11 7.74∠58.7° Ω

O"
-1
#
58.7°
Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚, then the maximum
allowable impedance reach is:
Eq. (23)

C
P Q
C
P Q

|CLMN 11 |

cosVOW65 H O"
-1
#
X
7.74 Ω
cosF85.0˚ H 58.7°G

61 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 1b and 7b
C
P Q

7.74 Ω
0.8965

C
P Q 8.633∠85.0° Ω

Example Calculations: Options 1c and 7c
Option 1c represents a more involved, more precise setting of the impedance element. This option requires
determining maximum generator Reactive Power output during field-forcing and the corresponding generator bus
voltage. Once these values are determined, the remainder of the calculation is the same as Options 1a and 1b.
The generator Reactive Power and generator bus voltage are determined by simulation. The maximum Reactive
Power output on the low-side of the GSU transformer during field-forcing is used as this value will correspond to
the lowest apparent impedance. The corresponding generator bus voltage is also used in the calculation. Note that
although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this
condition is sufficient to operate a phase distance relay.
In this simulation the following values are derived:
< 827.4 89:

,Y- 0.989 ; _ 21.76 V
The other value required is the Real Power output which is modeled in the simulation at 100% of the gross MW
capability reported to the Transmission Planner. In this case:

Real and Reactive Power (MW/Mvar)

Voltage (p.u.)

!_"
"# 700.0 %

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PRC-025-1— Generator Relay Loadability

Example Calculations: Options 1c and 7c
Apparent power (S):
Eq. (24)

/ !_"
"# @ A<

/ 700.0 % @ A827.4 89:
/ 1083.8∠49.8° MVA
Primary impedance (Zpri):
Eq. (25)

C
"1
C
"1

D
,Y/E

F21.76 GD
1083.8∠ H 49.8°

C
"1 0.437∠49.8° Ω
Secondary impedance (Zsec):
Eq. (26)

C- C
"1 ;

23"
1
!3"
1

C- 0.437∠49.8° Ω ;

DIJJJ
I
DJJ
K

C- 0.437∠49.8° Ω ; 25
C- 10.92∠49.8° Ω

To satisfy the 115% margin in the requirement in Options 1c and 7c:
Eq. (27)

CLMN 11
CLMN 11

C-
115%

10.92∠49.8° Ω
1.15

CLMN 11 9.50∠49.8° Ω

O"
-1
#
49.8°
Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚, then the maximum
allowable impedance reach is:
Eq. (28)

C
P Q
C
P Q

|CLMN 11 |

cosVOW65 H O"
-1
#
X
9.50 Ω
cosF85.0˚ H 49.8°G

63 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 1c and 7c
C
P Q

9.50 Ω
0.8171

C
P Q 11.63∠85.0° Ω
Example Calculations: Option 2a
Option 2a represents the simplest calculation for synchronous generators applying a phase time overcurrent (51V-R)
voltage restrained relay:
Real Power output (P):
Eq. (29)

! _

;
! 903 ; 0.85
! 767.6 %

Reactive Power output (Q):
Eq. (30)

< 150% ; !

< 1.50 ; 767.6 %
< 1151.3 89:

Option 2a, Table 1 – Bus Voltage, calls for a 0.95 per unit of the high-side nominal voltage for the generator bus
voltage (Vgen):
Eq. (31)

0.95 . =.; ; /0"
1
0.95 ; 345 ; >
20.81

22
?
346.5

Apparent power (S):
Eq. (32)

/ !_"
"# @ A<

/ 700.0 % @ A1151.3 89:
/ 1347.4∠58.7°
Primary current (Ipri):
Eq. (33)

g
"1

√3 ;

64 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 2a
g
"1

1347.4
1.73 ; 20.81

g
"1 37383
Secondary current (Isec):
Eq. (34)

g-
g-

g
"1
23"
1

37383
25000
5

g- 7.477

To satisfy the 115% margin in Option 2a:
Eq. (35)

gLMN 11 h g- ; 115%

gLMN 11 h 7.477 ; 1.15
gLMN 11 h 8.598

Example Calculations: Option 2b
Option 2b represents a more complex calculation for synchronous generators applying a phase time overcurrent (51)
or (51V-R) voltage restrained relay:
Real Power output (P):
Eq. (36)

! _

;
! 903 ; 0.85
! 767.6 %

Reactive Power output (Q):
Eq. (37)

< 150% ; !

< 1.50 ; 767.6 %
< 1151.3 89:

65 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 2b
Convert Real Power, Reactive Power, and transformer reactance to per unit values on 767.6 MVA base (MVAbase).
Real Power output (P):
Eq. (38)

!
Y
!
Y

!_"
"#
,
-
700.0 %
767.6

!
Y 0.91 . =.
Reactive Power output (Q):
Eq. (39)

<
Y
<
Y

<
,
-

1151.3 89:
767.6

<
Y 1.5 . =.
Transformer impedance:
Eq. (40)

(
Y (&'F#G ;

,
-
&'

(
Y 12.14% ; >
(
Y 0.1032 . =.

767.6
?
903

OZ[-1# sin[K ^
OZ[-1# sin[K ^
OZ[-1# 6.7°

Eq. (42)

|Z[-1# |
|Z[-1# |

V!
Y ; _(
Y _X

b
V|Z[-1# | ; `1[-1# aX
F0.91 ; 0.1032G
b
F0.95 ; 0.85G

_1[-1# _ ; cosFOZ[-1# G c d_1[-1# _ ; cos D FOZ[-1# G @ 4 ; <
Y ; (
Y
2

|0.85| ; cosF6.7°G c e|0.85|D ; cos D F6.7°G @ 4 ; 1.5 ; 0.1032
2
66 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 2b
|Z[-1# |
|Z[-1# |

|0.85| ; 0.9931 c √0.7225 ; 0.9864 @ 0.6192
2
0.8441 c 1.1541
2

|Z[-1# | 0.9991 . =.

Use the new estimated Vlow-side value of 0.9991 per unit for the second iteration:
Eq. (43)

OZ[-1# sin[K ^
OZ[-1# sin[K ^
OZ[-1# 6.3°

Eq. (44)

|Z[-1# |
|Z[-1# |
|Z[-1# |
|Z[-1# |

V!
Y ; _(
Y _X

b
V|Z[-1# | ; `1[-1# aX
F0.91 ; 0.1032G
b
F0.9991 ; 0.85G

_1[-1# _ ; cosFOZ[-1# G c d_1[-1# _ ; cos D FOZ[-1# G @ 4 ; <
Y ; (
Y
2

|0.85| ; cosF6.3°G c e|0.85|D ; cos D F6.3°G @ 4 ; 1.5 ; 0.1032
2
|0.85| ; 0.9940 c √0.7225 ; 0.9880 @ 0.6192
2
0.8449 c 1.1546
2

|Z[-1# | 0.9998 . =.

To account for system high-side nominal voltage and the transformer tap ratio:
Eq. (45)

,Y- |Z[-1# | ; ; /0"
1
,Y- 0.9998 . =.; 345 ; >
,Y- 21.90

22
?
346.5

Apparent power (S):
Eq. (46)

/ !_"
"# @ A<

/ 700.0 % @ A1151.3 89:
/ 1347.4∠58.7°

67 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 2b
Primary current (Ipri):
Eq. (47)

g
"1
g
"1

√3 ; ,Y-

1347.4
1.73 ; 21.90

g
"1 35553
Secondary current (Isec):
Eq. (48)

g-
g-

g
"1
23"
1

35553
25000
5

g- 7.111

To satisfy the 115% margin in Option 2b:
Eq. (49)

gLMN 11 h g- ; 115%

gLMN 11 h 7.111 ; 1.15
gLMN 11 h 8.178

Example Calculations: Option 2c
Option 2c represents a more involved, more precise setting of the overcurrent element for the phase time overcurrent
(51) or (51V-R) voltage restrained relay. This option requires determining maximum generator Reactive Power
output during field-forcing and the corresponding generator bus voltage. Once these values are determined, the
remainder of the calculation is the same as Options 2a and 2b.
The generator Reactive Power and generator bus voltage are determined by simulation. The maximum Reactive
Power output on the low-side of the GSU transformer during field-forcing is used as this value will correspond to
the highest current. The corresponding generator bus voltage is also used in the calculation. Note that although the
excitation limiter reduces the field, the duration of the Reactive Power output achieved for this condition is
sufficient to operate a voltage-restrained phase overcurrent relay.
In this simulation the following values are derived:
< 827.4 89:

,Y- 0.989 ; _ 21.76
The other value required is the Real Power output which is modeled in the simulation at 100% of the gross MW
capability reported to the Transmission Planner. In this case:

68 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 2c

Real and Reactive Power (MW/Mvar)

Voltage (p.u.)

!_"
"# 700.0 %

Apparent power (S):
Eq. (50)

/ !_"
"# @ A<

/ 700.0 % @ A827.4 89:
/ 1083.8∠49.8° MVA
Primary current (Ipri):
Eq. (51)

g
"1
g
"1

√3 ; ,Y-

1083.8
1.73 ; 21.76

g
"1 28790
Secondary current (Isec):
Eq. (52)

g-
g-

g
"1
23"
1

28790
25000
5

g- 5.758

69 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 2c
To satisfy the 115% margin in Option 2c:
Eq. (53)

gLMN 11 h g- ; 115%

gLMN 11 h 5.758 ; 1.15
gLMN 11 h 6.622

Example Calculations: Options 3 and 6
Option 3 represents the only calculation for synchronous generators applying a phase time overcurrent (51V-C) –
voltage controlled relay (Enabled to operate as a function of voltage). Similarly, Option 6 uses the same calculation
for asynchronous generators.
Options 3 and 6, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high-side nominal voltage for the generator
bus voltage (Vgen):
Eq. (54)

1.0 . =.; ; /0"
1
1.0 ; 345 ; >
21.9

22
?
346.5

The voltage setting shall be set less than 75% of the generator bus voltage:
Eq. (55)

-1 Q ; 75%

-1 Q 21.9 ; 0.75
-1 Q 16.429

Example Calculations: Option 4
This represents the calculation for an asynchronous generator (including inverter-based installations) applying a
phase distance relay (21) – directional toward the Transmission system.
Real Power output (P):
Eq. (56)

! 5-_

;
! 40 ; 0.85
! 34.0 %

70 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 4
Reactive Power output (Q):
Eq. (57)

< 5-_

; sinFcos [K FGG
< 40 ; sinFcos [K F0.85GG
< 21.1 89:

Option 4, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high-side nominal voltage for the generator bus
voltage (Vgen):
Eq. (58)

1.0 . =.; ; /0"
1
1.0 ; 345 ; >
21.9

22
?
346.5

Apparent power (S):
Eq. (59)

/ ! @ A<

/ 34.0 % @ A21.1 89:
/ 40.0∠31.8°
Primary impedance (Zpri):
Eq. (60)

C
"1
C
"1

F21.9 GD
40.0∠ H 31.8°

C
"1 11.99 ∠31.8° Ω
Secondary impedance (Zsec):
Eq. (61)

C- C
"1 ;

235-_"
1
!3"
1

C- 11.99 ∠31.8° Ω ;

IJJJ
I
DJJ
K

C- 11.99 ∠31.8° Ω ; 5
C- 59.95 ∠31.8° Ω

71 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 4
To satisfy the 130% margin in Option 4:
Eq. (62)

CLMN 11
CLMN 11

C-
130%

59.95∠31.8° Ω
1.30

CLMN 11 46.12∠31.8° Ω

O"
-1
#
31.8°
Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚, then the maximum
allowable impedance reach is:
Eq. (63)

C
P Q
C
P Q
C
P Q

|CLMN 11 |

cosVOW65 H O"
-1
#
X
46.12 Ω
cosF85.0° H 31.8°G
46.12 Ω
0.599

C
P Q 77.0∠85.0° Ω

Example Calculations: Option 5
This represents the calculation for three asynchronous generators applying a phase time overcurrent (51) or (51V-R)
– voltage-restrained relay. In this application it was assumed 20 Mvar of total static compensation was added.
Real Power output (P):
Eq. (64)

! 3 ; 5-_

;
! 3 ; 40 ; 0.85
! 102.0 %

Reactive Power output (Q):
Eq. (65)

< 7-
1 @ 7_-
1 @ V3 ; 5-_

; sinFcos [K FGGX
< 15 89: @ 5 89: @ F3 ; 40 ; sinFcos [K F0.85GGG
< 83.2 89:

72 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 5
Option 5, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high-side nominal voltage for the generator bus
voltage (Vgen):
Eq. (66)

1.0 . =.; ; /0"
1
1.0 ; 345 ; >
21.9

22
?
346.5

Apparent power (S):
Eq. (67)

/ ! @ A<

/ 102.0 % @ A83.2 89:
/ 131.6∠39.2°
Primary current (Ipri):
Eq. (68)

g
"1
g
"1

√3 ;

131.6∠ H 39.2°
1.73 ; 21.9

g
"1 3473∠ H 39.2°
Secondary current (Isec):
Eq. (69)

g-
g-

g
"1

235-_"
1

3473∠ H 39.2°
5000
5

g- 3.473∠ H 39.2°
To satisfy the 130% margin in Option 5:
Eq. (70)

gLMN 11 h g- ; 130%

gLMN 11 h 3.473∠ H 39.2° ; 1.30
gLMN 11 h 4.52∠ H 39.2°

73 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 7a and 10
This represents the calculation for a mixture of asynchronous (i.e., Option 10) and synchronous (i.e., Option 7a)
generation (including inverter-based installations) applying a phase distance relay (21) – directional toward the
Transmission system. In this application it was assumed 20 Mvar of total static compensation was added.
Synchronous Generation (Option 7a)
Real Power output (!- ):
Eq. (71)

! _

;
! 903 ; 0.85
! 767.6 %

Reactive Power output (<- ):
Eq. (72)

< 150% ; !

< 1.50 ; 767.6 %
< 1151.3 %
Apparent power (SSynch):
Eq. (73)

/ !_"
"# @ A<

/ 700.0 % @ A1151.3 89:
Asynchronous Generation (Option 10)
Real Power output (PAsynch):
Eq. (74)

!5- 3 ; 5-_

;
!5- 3 ; 40 ; 0.85
!5- 102.0 %

Reactive Power output (QAsynch):
Eq. (75)

<5- 7-
1 @ 7_-
1 @ V3 ; 5-_

; sinFcos [K FGGX
<5- 15 89: @ 5 89: @ F3 ; 40 ; sinFcos [K F0.85GGG
<5- 83.2 89:

Apparent power (SAsynch):
Eq. (76)

/5- !5- @ A<5-

74 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 7a and 10
/5- 102.0 % @ A83.2 89:
Options 7a and 10, Table 1 – Bus Voltage, Option 7a specifies 0.95 per unit of the high-side nominal voltage for the
generator bus voltage and Option 10 specifies 1.0 per unit of the high-side nominal voltage for generator bus
voltage. Due to the presence of the synchronous generator, the 0.95 per unit bus voltage will be used as (Vgen) as it
results in the most conservative voltage:
Eq. (77)

0.95 . =.; ; /0"
1
0.95 ; 345 ; >
20.81

22
?
346.5

Apparent power (S) accounted for 115% margin requirement for a synchronous generator and 130% margin
requirement for an asynchronous generator:
Eq. (78)

/ 115% ; V!_"
"# @ A< X @ 130% ; F!5- @ A<5- G

/ 1.15 ; F700.0 % @ A1151.3 89:G @ 1.30 ; F102.0 % @ A83.2 89:G
/ 1711.8 ∠56.8°
Primary impedance (Zpri):
Eq. (79)

C
"1
C
"1

F20.81 GD
1711.8∠ H 56.8°

C
"1 0.2527∠56.8° Ω
Secondary impedance (Zsec):
Eq. (80)

C- C
"1 ;

23"
1
!3"
1

C- 0.2527∠56.8° Ω ;

DIJJJ
I
DJJ
K

C- 0.2527∠56.8° Ω ; 25
C- 6.32∠56.8° Ω

75 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 7a and 10
No additional margin is needed; therefore, the margin is 100% because the synchronous apparent power has been
multiplied by 1.15 (115%) and the asynchronous apparent power has been multiplied by 1.30 (130%) in Equation 85
to satisfy the margin requirements in Options 7a and 10:
Eq. (81)

CLMN 11
CLMN 11

C-
100%

6.32 ∠56.8° Ω
1.00

CLMN 11 6.32 ∠56.8° Ω

O"
-1
#
56.8°
Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚, then the maximum
allowable impedance reach is:
Eq. (82)

C
P Q
C
P Q
C
P Q

|CLMN 11 |

cosVOW65 H O"
-1
#
X
6.32 Ω
cosF85.0° H 56.8°G
6.32 Ω
0.881

C
P Q 7.17∠85.0° Ω

Example Calculations: Options 8a and 9a
Options 8a and 9a represents the simplest calculation for synchronous generators applying a phase time overcurrent
(51) relay. The following uses the GENSynch_nameplate value to represent an “aggregate” value to illustrate the option:
Real Power output (P):
Eq. (83)

! _

;
! 903 ; 0.85
! 767.6 %

Reactive Power output (Q):
Eq. (84)

< 150% ; !

< 1.50 ; 767.6 %
< 1151.3 89:

76 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 8a and 9a
Options 8a and 9a, Table 1 – Bus Voltage, calls for a generator bus voltage corresponding to 0.95 per unit of the
high-side nominal voltage times the turns ratio of the generator step-up transformer generator bus voltage (Vgen):
Eq. (85)

0.95 . =.; ; /0"
1
0.95 ; 345 ; >
20.81

22
?
346.5

Apparent power (S):
Eq. (86)

/ !_"
"# @ A<

/ 700.0 % @ A1151.3 89:
/ 1347.4∠58.7°
Primary current (Ipri):
Eq. (87)

g
"1
g
"1

√3 ;

1347.4
1.73 ; 20.81

g
"1 37383
Secondary current (Isec):
Eq. (88)

g-
g-

g
"1
23"
1

37383
25000
5

g- 7.477

To satisfy the 115% margin in Options 8a and 9a:
Eq. (89)

gLMN 11 h g- ; 115%

gLMN 11 h 7.477 ; 1.15
gLMN 11 h 8.598

77 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 8b and 9b
Options 8b and 9b represents a more complex calculation for synchronous generators applying a phase time
overcurrent (51) relay. The following uses the GENSynch_nameplate value to represent an “aggregate” value to illustrate
the option:
Real Power output (P):
Eq. (90)

! _

;
! 903 ; 0.85
! 767.6 %

Reactive Power output (Q):
Eq. (91)

< 150% ; !

< 1.50 ; 767.6 %
< 1151.3 89:

Convert Real Power, Reactive Power, and transformer reactance to per unit values on 767.6 MVA base (MVAbase).
Real Power output (P):
Eq. (92)

!
Y
!
Y

!_"
"#
,
-
700.0 %
767.6

!
Y 0.91 . =.
Reactive Power output (Q):
Eq. (93)

<
Y
<
Y

<
,
-

1151.3 89:
767.6

<
Y 1.5 . =.
Transformer impedance:
Eq. (94)

(
Y (&'F#G ;

,
-
&'

(
Y 12.14% ; >
(
Y 0.1032 . =.

767.6
?
903

78 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 8b and 9b
Using the formula below; calculate the low-side GSU transformer voltage (Vlow-side) using 0.85 p.u. high-side voltage
(Vhigh-side). Estimate initial low-side voltage to be 0.95 p.u. and repeat the calculation as necessary until Vlow-side
converges. A convergence of less than one percent (<1%) between iterations is considered sufficient:
Eq. (95)

OZ[-1# sin[K ^
OZ[-1# sin[K ^

Eq. (96)

|Z[-1# |
|Z[-1# |
|Z[-1# |
|Z[-1# |

V!
Y ; _(
Y _X

b
V|Z[-1# | ; `1[-1# aX
F0.91 ; 0.1032G
b
F0.95 ; 0.85G

_1[-1# _ ; cosFOZ[-1# G c d_1[-1# _ ; cos D FOZ[-1# G @ 4 ; <
Y ; (
Y
2

|0.85| ; cosF6.7°G c e|0.85|D ; cos D F6.7°G @ 4 ; 1.5 ; 0.1032
2
|0.85| ; 0.9931 c √0.7225 ; 0.9864 @ 0.6192
2
0.8441 c 1.1541
2

|Z[-1# | 0.9991 . =.

Use the new estimated Vlow-side value of 0.9991 per unit for the second iteration:
Eq. (97)

OZ[-1# sin[K ^
OZ[-1# sin[K ^
OZ[-1# 6.3°

Eq. (98)

|Z[-1# |
|Z[-1# |
|Z[-1# |
|Z[-1# |

V!
Y ; _(
Y _X

b
V|Z[-1# | ; `1[-1# aX
F0.91 ; 0.1032G
b
F0.9991 ; 0.85G

_1[-1# _ ; cosFOZ[-1# G c d_1[-1# _ ; cos D FOZ[-1# G @ 4 ; <
Y ; (
Y
2

|0.85| ; cosF6.3°G c e|0.85|D ; cos D F6.3°G @ 4 ; 1.5 ; 0.1032
2
|0.85| ; 0.9940 c √0.7225 ; 0.9880 @ 0.6192
2
0.8449 c 1.1546
2

|Z[-1# | 0.9998 . =.

79 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 8b and 9b
To account for system high-side nominal voltage and the transformer tap ratio:
Eq. (99)

,Y- |Z[-1# | ; ; /0"
1
,Y- 0.9998 . =.; 345 ; >
,Y- 21.90

22
?
346.5

Apparent power (S):
Eq. (100)

/ !_"
"# @ A<

/ 700.0 % @ A1151.3 89:
/ 1347.4∠58.7°
Primary current (Ipri):
Eq. (101)

g
"1
g
"1

√3 ; ,Y-

1347.4
1.73 ; 21.90

g
"1 35553
Secondary current (Isec):
Eq. (102)

g-
g-

g
"1
23"
1

35553
25000
5

g- 7.111

To satisfy the 115% margin in Options 8b and 9b:
Eq. (103)

gLMN 11 h g- ; 115%

gLMN 11 h 7.111 ; 1.15
gLMN 11 h 8.178

80 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 8a, 9a, 11, and 12
This represents the calculation for a mixture of asynchronous and synchronous generators applying a phase time
overcurrent. In this application it was assumed 20 Mvar of total static compensation was added. The current
transformers (CT) are located on the low-side of the GSU transformer.
Synchronous Generation (Options 8a and 9a)
Real Power output (PSynch):
Eq. (104)

! _

;
! 903 ; .85
! 767.6 %

Reactive Power output (QSynch):
Eq. (105)

< 150% ; !

< 1.50 ; 767.6 %
< 1151.3 89:
Apparent power (SSynch):
Eq. (106)

/ !_"
"# @ A<

/ 700.0 % @ A1151.3 89:
/ 1347.4 ∠58.7°

Option 8a, Table 1 – calls for a 0.95 per unit of the high-side nominal voltage for generator bus voltage (Vgen):
Eq. (107)

0.95 . =.; ; /0"
1
0.95 ; 345 ; >
20.81

22
?
346.5

Primary current (Ipri-sync):
Eq. (108)

g
"1[-
g
"1[-

E
115% ; /

√3 ;

1.15 ; F1347.4 ∠ H 58.7° G
1.73 ; 20.81

g
"1[- 43061 ∠ H 58.7°

81 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 8a, 9a, 11, and 12
Asynchronous Generation (Options 11 and 12)
Real Power output (PAsynch):
Eq. (109)

!5- 3 ; 5-_

;
!5- 3 ; 40 ; 0.85
!5- 102.0 %

Reactive Power output (QAsynch):
Eq. (110)

<5- 7-
1 @ 7_-
1 @ 5-_

; sinFcos [K FGG
<5- 15 89: @ 5 89: @ F3 ; 40 ; sinFcos [K F0.85GGG
<5- 83.2 89:

Option 11, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high-side nominal voltage for the generator bus
voltage (Vgen), however due to the presence of synchronous generator 0.95 per unit bus voltage will be used:
Eq. (111)

0.95 . =.; ; /0"
1
0.95 ; 345 ; >
20.81

22
?
346.5

Apparent power (SAsynch):
Eq. (112)

/5- 130% ; F!5- @ A<5- G

/5- 1.30 ; F102.0 % @ A83.2 89:G
/5- 171.1 ∠39.2°
Primary current (Ipri-async):
Eq. (113)

g
"1[
-
g
"1[
-

/5-

√3 ;

171.1 ∠ H 39.2°
1.73 ; 20.81

g
"1[
- 4755 ∠ H 39.2°
Secondary current (Isec):
Eq. (114)

g
"1[- g
"1[
-
@
23"
1
23"
1
82 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 8a, 9a, 11, and 12
g-

43061 ∠ H 58.7°
4755∠ H 39.2°
@
25000
25000
5
5

g- 9.514∠ H 56.8°

No additional margin is needed; therefore, the margin is 100% because the synchronous apparent power has been
multiplied by 1.15 (115%) in Equation 94 and the asynchronous apparent power has been multiplied by 1.30 (130%)
in Equation 98:
Eq. (115)

gLMN 11 h g- ; 100%

gLMN 11 h 9.514∠ H 56.8° ; 1.00
gLMN 11 h 9.514∠ H 56.8°

Example Calculations: Options 8c and 9c
This example uses Option 15b as a simulation example for a synchronous generator applying a phase time
overcurrent relay. In this application the same synchronous generator is modeled as for Options 1c, 2c, and 7c. The
CTs are located on the low-side of the GSU transformer.
The generator Reactive Power and generator bus voltage are determined by simulation. The maximum Reactive
Power output on the low-side of the GSU transformer during field-forcing is used as this value will correspond to
the highest current. The corresponding generator bus voltage is also used in the calculation. Note that although the
excitation limiter reduces the field, the duration of the Reactive Power output achieved for this condition is
sufficient to operate a phase overcurrent relay.
< 827.4 89:

,Y- 0.989 ; 21.76
The other value required is the Real Power output which is modeled in the simulation at 100% of the gross MW
capability reported to the Transmission Planner. In this case:
!"
"# 700.0 %

83 of 99

PRC-025-1— Generator Relay Loadability

Real and Reactive Power (MW/Mvar)

Voltage (p.u.)

Example Calculations: Options 8c and 9c

Apparent power (S):
Eq. (116)

/ !_"
"# @ A<

/ 700.0 % @ A827.4 89:
/ 1083.8∠49.8°
Primary current (Ipri):
Eq. (117)

g
"1
g
"1

√3 ; ,Y-

1083.8
1.73 ; 21.76

g
"1 28790
Secondary current (Isec):
Eq. (118)

g-
g-

g
"1
23"
1

28790
25000
5

g- 5.758

84 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 8c and 9c
To satisfy the 115% margin in Options 8c and 9c:
Eq. (119)

gLMN 11 h g- ; 115%

gLMN 11 h 5.758 ; 1.15
gLMN 11 h 6.622

Example Calculations: Option10
This represents the calculation for three asynchronous generators (including inverter-based installations) applying a
phase distance relay (21) – directional toward the Transmission system. In this application it was assumed 20 Mvar
of total static compensation was added.
Real Power output (P):
Eq. (120)

! 3 ; 5-_

;
! 3 ; 40 ; 0.85
! 102.0 %

Reactive Power output (Q):
Eq. (121)

< 7-
1 @ 7_-
1 @ V3 ; 5-_

; sinFcos [K FGGX
< 15 89: @ 5 89: @ F3 ; 40 ; sinFcos [K F0.85GGG
< 83.2 89:

Option 10, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high-side nominal voltage for the generator bus
voltage (Vgen):
Eq. (122)

1.0 . =.; ; /0"
1
1.0 ; 345 ; >
21.9

22
?
346.5

Apparent power (S):
Eq. (123)

/ ! @ A<

/ 102.0 % @ A83.2 89:
/ 131.6∠39.2°

85 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option10
Primary impedance (Zpri):
Eq. (124)

C
"1
C
"1

F21.9 GD
131.6∠ H 39.2°

C
"1 3.644 ∠39.2° Ω
Secondary impedance (Zsec):
Eq. (125)

C- C
"1 ;

235-_"
1
!3"
1

C- 3.644 ∠39.2° Ω ;

IJJJ
I
DJJ
K

C- 3.644 ∠39.2° Ω ; 5
C- 18.22 ∠39.2° Ω

To satisfy the 130% margin in Option 10:
Eq. (126)

CLMN 11
CLMN 11

C-
130%

18.22∠39.2° Ω
1.30

CLMN 11 14.02∠39.2° Ω

O"
-1
#
39.2°
Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚, then the maximum
allowable impedance reach is:
Eq. (127)

C
P Q
C
P Q
C
P Q

|CLMN 11 |

cosVOW65 H O"
-1
#
X
14.02 Ω
cosF85.0° H 39.2°G
14.02 Ω
0.6972

C
P Q 20.11∠85.0° Ω

86 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 11 and 12
Option 11 represents the calculation for a GSU transformer applying a phase time overcurrent (51) relay connected
to three asynchronous generators. Similarly, these calculations can be applied to Option 12 for a phase directional
time overcurrent relay (67) directional toward the Transmission system. In this application it was assumed 20 Mvar
of total static compensation was added.
Real Power output (P):
Eq. (128)

! 3 ; 5-_

;
! 3 ; 40 ; 0.85
! 102.0 %

Reactive Power output (Q):
Eq. (129)

< 7-
1 @ 7_-
1 @ V3 ; 5-_

; sinFcos [K FGGX
< 15 89: @ 5 89: @ F3 ; 40 ; sinFcos [K F0.85GGG
< 83.2 89:

Options 11 and 12, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high-side nominal voltage for the generator
bus voltage (Vgen):
Eq. (130)

1.0 . =.; ; /0"
1
1.0 ; 345 ; >
21.9

22
?
346.5

Apparent power (S):
Eq. (131)

/ ! @ A<

/ 102.0 % @ A83.2 89:
/ 131.6 ∠39.2°
Primary current (Ipri):
Eq. (132)

g
"1
g
"1

√3 ;

131.6 ∠ H 39.2°
1.73 ; 21.9

g
"1 3473∠ H 39.2°

87 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 11 and 12
Secondary current (Isec):
Eq. (133)

g-
g-

g
"1

235-_"
1

3473∠ H 39.2°
5000
5

g- 3.473∠ H 39.2°
To satisfy the 130% margin in Options 11 and12:
Eq. (134)

gLMN 11 h g- ; 130%

gLMN 11 h 3.473∠ H 39.2° ; 1.30
gLMN 11 h 4.515∠ H 39.2°

Example Calculations: Options 13a and 13b
Option 13a for the UAT assumes that the maximum nameplate rating of the winding utilized for the purposes of the
calculations and the appropriate voltage. Similarly, Option 13b uses the measured current while operating at the
maximum gross MW capability reported to the Transmission Planner.
Primary current (Ipri):
Eq. (135)

g
"1
g
"1

√3 ; '56

60
1.73 ; 13.8

g
"1 2510.2
Secondary current (Isec):
Eq. (136)

g-
g-

g
"1
23'56

2510.2
5000
5

g- 2.51 A

To satisfy the 150% margin in Options 13a:
Eq. (137)

gLMN 11 h g- ; 150%
88 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 13a and 13b
gLMN 11 h 2.51 ; 1.50
gLMN 11 h 3.77

Example Calculations: Option 14a
Option 14a represents the calculation for synchronous generation Elements that connect the GSU transformer(s) to
the Transmission system that are used exclusively to export energy directly from a BES generating unit or
generating plant (Elements may also supply generating plant loads.) that is applying a phase distance (21) relay
directional toward the Transmission system. The CTs are located on the high-side of the GSU transformer.
Real Power output (P):
Eq. (138)

! _

;
! 903 ; 0.85
! 767.6 %

Reactive Power output (Q):
Eq. (139)

< 120% ; !

< 1.20 ; 767.6 %
< 921.1 89:

Option 14a, Table 1 – Bus Voltage, calls for a 0.85 per unit of the high-side nominal voltage for the GSU
transformer voltage (Vnom):
Eq. (140)

,Y- 0.85 . =.;
0.85 ; 345
293.25

Apparent power (S):
Eq. (141)

/ !_"
"# @ A<

/ 700.0 % @ A921.1 89:
/ 1157.0∠52.77°

O"
-1
#
52.77°

89 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 14a
Primary impedance (Zpri):
Eq. (142)

C
"1
C
"1

D
,Y/E

F293.25 GD
1157.0∠ H 52.77°

C
"1 74.335∠52.77° Ω
Secondary impedance (Zsec):
Eq. (143)

C- C
"1 ;

23"
1_4
!3"
1_4
DJJJ

I
C- 74.335∠52.77° Ω ; DJJJ
K

C- 74.335∠52.77° Ω ; 0.2
C- 14.867∠52.77° Ω

To satisfy the 115% margin in Option 14a:
Eq. (144)

CLMN 11
CLMN 11

C-
115%

14.867∠52.77° Ω
1.15

CLMN 11 12.928∠52.77° Ω
O"
-1
#
52.77°

Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚, then the maximum
allowable impedance reach is:
Eq. (145)

C
P Q
C
P Q
C
P Q

|CLMN 11 |

cosVOW65 H O"
-1
#
X
12.928 Ω
cosF85.0° H 52.77°G
12.928 Ω
0.846

C
P Q 15.283∠85.0° Ω

90 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 14b
Option 14b represents the simulation for synchronous generation Elements that connect the GSU transformer(s) to
the Transmission system that are used exclusively to export energy directly from a BES generating unit or
generating plant (Elements may also supply generating plant loads.) that is applying a phase distance (21) relay
directional toward the Transmission system. The CTs are located on the high-side of the GSU transformer.
The Reactive Power flow and high-side bus voltage are determined by simulation. The maximum Reactive Power
output on the high-side of the GSU transformer during field-forcing is used as this value will correspond to the
lowest apparent impedance. The corresponding high-side bus voltage is also used in the calculation. Note that
although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this
condition is sufficient to operate a phase distance relay.
In this simulation the following values are derived:
< 703.6 89:

,Y- 0.908 ; 313.3
The other value required is the Real Power output which is modeled in the simulation at 100% of the gross MW
capability reported to the Transmission Planner. In this case:
!"
"# 700.0 %

Apparent power (S):
Eq. (146)

/ !_"
"# @ A<

/ 700.0 % @ A703.6 89:
/ 992.5∠45.1°

O"
-1
#
45.1°
91 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 14b
Primary impedance (Zpri):
Eq. (147)

C
"1
C
"1

D
,Y/E

F313.3 GD
992.5∠ H 45.1°

C
"1 98.90∠45.1° Ω
Secondary impedance (Zsec):
Eq. (148)

C- C
"1 ;

23"
1_4
!3"
1_4
DJJJ

I
C- 98.90∠45.1° Ω ; DJJJ
K

C- 98.90∠45.1° Ω ; 0.2
C- 19.78∠45.1° Ω

To satisfy the 115% margin in Option 14b:
Eq. (149)

CLMN 11
CLMN 11

C-
115%

19.78∠45.1° Ω
1.15

CLMN 11 17.20∠45.1° Ω

O"
-1
#
45.1°
Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚, then the maximum
allowable impedance reach is:
Eq. (150)

C
P Q
C
P Q
C
P Q

|CLMN 11 |

cosVOW65 H O"
-1
#
X
17.20 Ω
cosF85.0° H 45.1°G
17.20 Ω
0.767

C
P Q 22.42∠85.0° Ω

92 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 15a and 16a
Options 15a and 16a represent the calculation for synchronous generation Elements that connect the GSU
transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating
unit or generating plant. Elements may also supply generating plant loads. Option 15a represents applying a phase
overcurrent supervisory element (50) – associated with current-based, communication-assisted schemes where the
scheme is capable of tripping for loss of communications installed on the high-side of the GSU transformer or phase
time overcurrent relay (51) – installed on the high-side of the GSU transformer. Option 16a represents applying a
phase directional overcurrent supervisory elements (67) – associated with current-based, communication-assisted
schemes where the scheme is capable of tripping for loss of communications – directional toward the Transmission
system– installed on the high-side of the GSU transformer or phase directional time overcurrent relay (67) –
directional toward the Transmission system installed on the high-side of the GSU transformer.
This example uses Option 15a as an example, where PTs and CTs are located in the high-side of the GSU
transformer.
Real Power output (P):
Eq. (151)

! _

;
! 903 ; 0.85
! 767.6 %

Reactive Power output (Q):
Eq. (152)

< 120% ; !

< 1.20 ; 767.6 %
< 921.12 89:

Option 15a, Table 1 – Bus Voltage, calls for a 0.85 per unit of the high-side nominal voltage:
Eq. (153)

,Y- 0.85 . =.;
,Y- 0.85 ; 345
,Y- 293.25

Apparent power (S):
Eq. (154)

/ !_"
"# @ A<

/ 700.0 % @ A921.12 89:
/ 1157∠52.8°
Primary current (Ipri):
Eq. (155)

g
"1

√3 ; ,Y-

93 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 15a and 16a
g
"1

1157j H 52.8°
1.73 ; 293.25

g
"1 2280.6j H 52.8°
Secondary current (Isec):
Eq. (156)

g-
g-

g
"1

23"
1_4

2280.6j H 52.8°
2000
5

g- 5.701 j H 52.8°

To satisfy the 115% margin in Options 15a and 15b:
Eq. (157)

gLMN 11 h g- ; 115%

gLMN 11 h 5.701 j H 52.8° ; 1.15
gLMN 11 h 6.56 j H 52.8°

Example Calculations: Options 15b and 16b
Options 15b and 16b represent the calculation for synchronous generation Elements that connect the GSU
transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating
unit or generating plant. Elements may also supply generating plant loads. Option 15b represents applying a phase
overcurrent supervisory element (50) – associated with current-based, communication-assisted schemes where the
scheme is capable of tripping for loss of communications installed on the high-side of the GSU transformer or phase
time overcurrent relay (51) – installed on the high-side of the GSU transformer. Option 16b represents applying a
phase directional overcurrent supervisory element (67) – associated with current-based, communication-assisted
schemes where the scheme is capable of tripping for loss of communications directional toward the Transmission
system installed on the high-side of the GSU transformer or phase directional time overcurrent relay (67) –
directional toward the Transmission system installed on the high-side of the GSU transformer.
This example uses Option 15b as a simulation example, where PTs and CTs are located in the high-side of the GSU
transformer.
The Reactive Power flow and high-side bus voltage are determined by simulation. The maximum Reactive Power
output on the high-side of the GSU transformer during field-forcing is used as this value will correspond to the
lowest apparent impedance. The corresponding high-side bus voltage is also used in the calculation. Note that
although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this
condition is sufficient to operate a phase overcurrent relay.
In this simulation the following values are derived:
< 703.6 89:

,Y- 0.908 ; 313.3
94 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 15b and 16b
The other value required is the Real Power output which is modeled in the simulation at 100% of the gross MW
capability reported to the Transmission Planner. In this case:
!"
"# 700.0 %

Apparent power (S):
Eq. (158)

/ !_"
"# @ A<

/ 700.0 % @ A703.6 89:
/ 992.5∠45.1°
Primary current (Ipri):
Eq. (159)

g
"1
g
"1

√3 ; ,Y-

992.5∠ H 45.1°
1.73 ; 313.3

g
"1 1831.2j H 45.1°
Secondary current (Isec):
Eq. (160)

g
"1
23"
1_4

95 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 15b and 16b
g-

1831.2j H 45.1°
2000
5

g- 4.578 j H 45.1°

To satisfy the 115% margin in Options 15b and 16b:
Eq. (161)

gLMN 11 h g- ; 115%

gLMN 11 h 4.578 j H 45.1° ; 1.15
gLMN 11 h 5.265 j H 45.1°

Example Calculations: Option 17
Option 17 represents the calculation for three asynchronous generation Elements that connect the GSU
transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating
unit or generating plant (Elements may also supply generating plant loads.) that is applying a phase distance relay
(21) - directional toward the Transmission system. In this application it was assumed 20 Mvar of total static
compensation was added.
Real Power output (P):
Eq. (162)

!5- 3 ; 5-_

;
!5- 3 ; 40 ; 0.85
!5- 102.0 %

Reactive Power output (Q):
Eq. (163)

<5- 7-
1 @ 7_-
1 @ V3 ; 5-_

; sinFcos [K FGGX
<5- 15 89: @ 5 89: @ F3 ; 40 ; sinFcos [K F0.85GGG
<5- 83.2 89:

Option 17, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high-side nominal voltage for the bus voltage (Vbus):
Eq. (164)

,Y- 1.0 . =.;
1.0 ; 345
345.0

Apparent power (S):
Eq. (165)

/ ! @ A<
96 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 17
/ 102.0 % @ A83.2 89:
/ 131.6∠39.2°
Primary impedance (Zpri):
Eq. (166)

C
"1
C
"1

D
,Y/E

F345.0 GD
131.6∠ H 39.2°

C
"1 904.4∠39.2° Ω
Secondary impedance (Zsec):
Eq. (167)

C- C
"1 ;

235-_"
1_4
!3"
1_4
kJJ

I
C- 904.4∠39.2° Ω ; DJJJ
K

C- 904.4∠39.2° Ω ; 0.03
C- 27.13∠39.2° Ω

To satisfy the 130% margin in Option 17:
Eq. (168)

CLMN 11
CLMN 11

C-
130%

27.13∠39.2° Ω
1.30

CLMN 11 20.869∠39.2° Ω
O"
-1
#
39.2°

Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚, and then the maximum
allowable impedance reach is:
Eq. (169)

C
P Q
C
P Q
C
P Q

|CLMN 11 |

cosVOW65 H O"
-1
#
X
20.869 Ω
cosF85.0° H 39.2°G
20.869 Ω
0.697

97 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Option 17
C
P Q 29.941∠85.0° Ω

Example Calculations: Options 18 and 19
Option 18 represents the calculation for three asynchronous generation Elements that connect the GSU
transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating
unit or generating plant (Elements may also supply generating plant loads.) that is applying a phase time overcurrent
(51) relay connected to three asynchronous generators. Similarly, Option 19 may also be applied here for the phase
directional time overcurrent relays (67) directional toward the Transmission system for Elements that connect the
GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES
generating unit or generating plant. Elements may also supply generating plant loads. In this application it was
assumed 20 Mvar of total static compensation was added.
Real Power output (P):
Eq. (170)

! 3 ; 5-_

;
! 3 ; 40 ; 0.85
! 102.0 %

Reactive Power output (Q):
Eq. (171)

< 7-
1 @ 7_-
1 @ V3 ; 5-_

; sinFcos [K FGGX
< 15 89: @ 5 89: @ F3 ; 40 ; sinFcos [K F0.85GGG
< 83.2 89:

Options 18 and 19, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high-side nominal voltage (Vbus):
Eq. (172)

1.0 . =.;
,Y- 1.0 ; 345
,Y- 345

Apparent power (S):
Eq. (173)

/ ! @ A<

/ 102.0 % @ A83.2 89:
/ 131.6∠39.2°
Primary current (Ipri):
Eq. (174)

g
"1

√3 ; ,Y98 of 99

PRC-025-1— Generator Relay Loadability

Example Calculations: Options 18 and 19
g
"1

131.6∠ H 39.2°
1.73 ; 345

g
"1 220.5 ∠ H 39.2°
Secondary current (Isec):
Eq. (175)

g-
g-

g
"1
235-_"
1_4

220.5∠ H 39.2°
300
5

g- 3.675∠ H 39.2°

To satisfy the 130% margin in Options 18 and 19:
Eq. (176)

gLMN 11 h g- ; 130%

gLMN 11 h 3.675∠ H 39.2° ; 1.30
gLMN 11 h 4.778∠ H 39.2°

End of calculations

99 of 99

File Type	application/pdf
File Title	Microsoft Word - PRC_025_1_Complete
Author	walkerb
File Modified	2014-07-16
File Created	2013-09-30