PRC-025-2: Generator Relay Loadability

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.

Applicability

4.1.         Functional Entities:

4.1.1.     Generator Owner that applies load-responsive protective relays1  at the terminals of the Elements listed in 4.2, Facilities.

4.1.2.     Transmission Owner that applies load-responsive protective relays1

at the terminals of the Elements listed in 4.2, Facilities.

4.1.3.     Distribution Provider that applies load-responsive protective relays1

at the terminals of the Elements listed in 4.2, Facilities.

4.2.          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:

4.2.1.     Generating unit(s).

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

4.2.3.     Unit auxiliary transformer(s) (UAT) that supply overall auxiliary power necessary to keep generating unit(s) online.2

4.2.4.     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, except that Elements may also supply generating plant loads.

4.2.5.     Elements utilized in the aggregation of dispersed power producing resources.

Effective Date: See Implementation Plan

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.3

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.

 Standard Only Definition: None


Requirements and Measures

R1.    Each Generator Owner, Transmission Owner, and Distribution Provider shall apply settings that are in accordance with PRC-025-2 – 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, spreadsheets, simulation reports, or setting sheets) that settings were applied in accordance with PRC-025-2 – Attachment 1: Relay Settings.


Compliance

1. Compliance Monitoring Process

1.1.          Compliance  Enforcement  Authority:  “Compliance  Enforcement  Authority” means NERC or the Regional Entity, or any entity as otherwise designated by an Applicable Governmental Authority, in their respective roles of monitoring and/or  enforcing  compliance  with  mandatory  and  enforceable  Reliability Standards in their respective jurisdictions.

1.2.          Evidence Retention: The following evidence retention period(s) identify the period of time an entity is required to retain specific evidence to demonstrate compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit.

The applicable entity shall keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation:

Regional Variances

None.

Associated Documents

NERC System Protection and Control Subcommittee, “Considerations for Power Plant and Transmission System Protection Coordination,” technical reference document, Revision 2. (Date of Publication: July 2015)

NERC System Protection and Control Subcommittee, “Unit Auxiliary Transformer Overcurrent Relay Loadability During a Transmission Depressed Voltage Condition.” (Date of Publication: March 2016)

IEEE C37.102-2006, “IEEE Guide for AC Generator Protection.” (Date of Publication: 2006)

IEEE C37.17-2012, “IEEE Standard for Trip Systems for Low-Voltage (1000 V and below) AC and General Purpose (1500 V and below) DC Power Circuit Breakers.” (Date of Publication: September 18, 2012)

IEEE C37.2-2008, “IEEE Standard for Electrical Power System Device Function Numbers, Acronyms, and Contact Designations.” (Date of Publication: October 3, 2008)


PRC-025-2 – 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 4.2, 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 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 as a minimum requirement. The Generator Owner may base settings on a capability that is higher than what is reported to the Transmission Planner.

Asynchronous generator relay 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. If different seasonal capabilities are reported, the maximum capability shall be used for the purposes of this standard as a minimum requirement. The Generator Owner may base settings on a capability that is higher than what is reported to the Transmission Planner.

For applications 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 (except that Elements may also supply generating plant loads), the setting criteria shall be determined by vector summing the 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 de-energized 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 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 (except that 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., non-directional 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 Remedial Action Schemes 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 full load current (e.g., rated armature current), and prevent operation below 115% of full-load current.4

7. Protection systems that detect overloads and are designed only to respond in time periods which allow an operator 15 minutes or greater to respond to overload condition

8. Low voltage protection devices that do not have adjustable settings.

Table 1

Table 1 below 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). 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 distance or overcurrent protective relay by IEEE device numbers (e.g., 21, 50, 51, 51V-C, 51V-R, or 67) according to the application in the first column. This also includes manufacture protective device trip unit designations for long-time delay, short-time delay, and instantaneous (e.g., L, S, and I). 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, except when the same application continues on the next page of the table with a different relay type.

The third column uses numeric and alphabetic options (i.e., index numbering) to identify the available options for setting load-responsive 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 setting criteria in the fourth and fifth column, respectively. The bus voltage column and 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.

 Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

Phase distance relay (e.g., 21) – directional toward the Transmission system

 

 

 

1a

 

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

OR
 

 

 

 

1b

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 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

OR
 

 

 

 

1c

Simulated 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 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

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

 

Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

Phase overcurrent relay (e.g., 50, 51, or 51V-R – voltage- restrained)

 

 

 

2a

 

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

OR
 

 

 

 

2b

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, and

(2) Reactive Power output – 150% of the MW value, derived

from the generator nameplate MVA rating at rated power factor

OR
 

 

 

 

2c

Simulated 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 generator step-up transformer prior to field-forcing

 

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

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

 

 

 

3

 

 

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

 

Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
 

 

 

 

 

 

 

 

 

 

 

Asynchronous generating unit(s) (including inverter- based installations), including Elements utilized in the aggregation of dispersed power producing resources

Phase distance

relay (e.g., 21) – directional toward the Transmission system

 

 

4

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)

 

 

 

 

Phase overcurrent relay (e.g., 50, 51, or 51V-R – voltage- restrained)

 

 

5a

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)

OR
 

 

5b

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 lower tolerance of the overcurrent element tripping characteristic shall not infringe upon the resource capability (including the Mvar output of the resource and any static or dynamic reactive power devices) See Figure A.
Phase time overcurrent relay (e.g., 51V-C) – voltage controlled (Enabled to operate as a function of voltage)  

 

 

 

6

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

 

Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
 

 

 

 

 

 

 

 

 

 

 

 

 

Relays installed on generator-side 7 of the Generator step-up transformer(s) connected to synchronous generators

 

 

 

 

 

 

 

 

 

 

 

 

Phase distance relay (e.g., 21) – directional toward the Transmission system

 

 

 

 

7a

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

OR
 

 

 

 

7b

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 – 150% of the aggregate generation

MW value, derived from the generator nameplate MVA rating at rated power factor

OR
 

 

 

 

7c

Simulated 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 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

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

 

Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
 

 

 

 

 

 

 

 

 

 

 

 

Relays installed on generator-side 8 of the Generator step-up transformer(s) connected to synchronous generators

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Phase overcurrent relay (e.g., 50 or

51)

 

 

 

 

8a

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

OR
 

 

 

 

8b

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 – 150% of the aggregate generation

MW value, derived from the generator nameplate MVA rating at rated power factor

OR
 

 

 

 

8c

Simulated 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 generator step-up transformer prior to field-forcing

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

 

Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
 

 

 

 

 

 

 

 

 

 

 

Relays installed on generator-side 9 of the Generator step-up transformer(s) connected to synchronous generators

 

 

 

 

 

 

 

 

 

 

 

 

Phase directional overcurrent relay (e.g., 67) – directional toward the Transmission system

 

 

 

 

9a

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

OR
 

 

 

 

9b

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 – 150% of the aggregate generation

MW value, derived from the generator nameplate MVA rating at rated power factor

OR
 

 

 

 

9c

Simulated 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 generator step-up transformer prior to field-forcing

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

 

Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
 

 

 

 

 

 

 

Relays installed on generator-side of the Generator step-up transformer(s) connected to asynchronous generators only (including inverter- based installations)

Phase distance

relay (e.g., 21) – directional toward the Transmission system 10

 

 

10

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)

 

 

Phase overcurrent relay (e.g., 50 or

51) 11

 

 

 

11

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

 

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)

Phase directional

overcurrent relay (e.g., 67) – directional toward the Transmission system 12

 

 

 

12

 

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)

A different application starts on the next page

 

 

Table 1. Relay Loadability Evaluation Criteria

Application Relay Type Option Bus Voltage5 Setting Criteria
 

 

 

 

Unit auxiliary transformer(s) (UAT)

Phase overcurrent relay (e.g., 50 or

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
OR
 

 

13b

 

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

Relays installed on the high-side of the GSU transformer, 13 including relays installed on the remote end of line, 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

(except that Elements may also supply generating plant loads)

– connected to

synchronous generators

 

 

 

 

 

 

Phase distance relay (e.g., 21) – directional toward the Transmission system

 

 

 

 

14a

 

 

 

0.85 per unit of the line nominal voltage at the relay location

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

OR
 

 

 

 

14b

Simulated line voltage at the relay location coincident with the highest Reactive Power output achieved during field-forcing in response to a

0.85 per unit of the line nominal voltage at the remote end of the line 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

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

 

Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
Relays installed on the high-side of the GSU transformer, 14 including relays installed at the remote end of the line, 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 (except that Elements may also supply generating plant loads)

– connected to synchronous generators

Phase instantaneous overcurrent supervisory

element (e.g., 50) – associated with current-based, communication- assisted schemes where the scheme is capable of tripping for loss of communications and/or phase time overcurrent relay (e.g., 51)

 

 

 

 

15a

 

 

 

0.85 per unit of the line nominal voltage at the relay location

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

OR
 

 

 

 

15b

Simulated line voltage at the relay location coincident with the highest Reactive Power output achieved during field-forcing in response to a

0.85 per unit of the line nominal voltage at the remote end of the line prior to field-forcing

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

 

Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
 

Relays installed on the high-side of the GSU transformer, 15 including relays installed at the remote end of the line, 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 (except that Elements may also supply generating plant load.)

–connected to synchronous generators

Phase directional instantaneous overcurrent supervisory

element (e.g., 67) – associated with current-based, communication- assisted schemes where the scheme is capable of tripping for loss of communications directional toward the Transmission system and/or phase directional time overcurrent relay (e.g., 67) – directional toward the Transmission system

 

 

 

 

16a

 

 

 

0.85 per unit of the line nominal voltage at the relay location

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

OR
 

 

 

 

 

 

 

 

16b

 

 

 

 

Simulated line voltage at the relay location coincident with the highest Reactive Power output achieved during field-forcing in response to a

0.85 per unit of the line nominal

voltage at the remote end of the line prior to field-forcing

 

 

 

 

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

 

Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
Relays installed on the

high-side of the GSU transformer, 16 including relays installed on the remote end of line, 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

(except that Elements may also supply generating plant loads)

–connected to asynchronous generators only (including inverter- based installations)

Phase distance

relay (e.g., 21) – directional toward the Transmission system

 

 

17

 

 

1.0 per unit of the line nominal voltage at the relay location

 

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)

 

 

 

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

 

 

Table 1. Relay Loadability Evaluation Criteria
Application Relay Type Option Bus Voltage5 Setting Criteria
Relays installed on the

high-side of the GSU transformer, 17 including, relays installed on the remote end of the line, 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

(except that Elements

may also supply generating plant loads)

– connected to

asynchronous generators only (including inverter- based installations)

Phase

instantaneous overcurrent supervisory

element (e.g., 50) – associated with current-based, communication- assisted schemes where the scheme is capable of tripping for loss of communications and/or Phase time overcurrent relay (e.g., 51)

 

 

 

 

 

 

 

 

 

18

 

 

 

 

 

 

 

 

 

1.0 per unit of the line nominal voltage at the relay location

 

 

 

 

 

 

 

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)

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

 

 

 

Table 1. Relay Loadability Evaluation Criteria

Application Relay Type Option Bus Voltage5 Setting Criteria
Relays installed on the

high-side of the GSU transformer, 18 including relays installed on the remote end of the line, 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 (except that Elements may also supply generating plant loads)

–connected to

asynchronous generators only (including inverter- based installations)

 

 

Phase directional instantaneous overcurrent supervisory

element (e.g., 67) – associated with current-based, communication- assisted schemes where the scheme is capable of tripping for loss of communications directional toward the Transmission system and/or Phase directional time overcurrent relay (e.g., 67)

 

 

 

 

 

 

 

 

 

 

 

 

 

19

 

 

 

 

 

 

 

 

 

 

 

 

1.0 per unit of the line nominal voltage at the relay location

 

 

 

 

 

 

 

 

 

 

 

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)

End of Table 1

 

 


PRC-025-2 Guidelines and Technical Basis

 

Introduction

The   document,   “Considerations  for  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 2015.[18: https://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20Gen%20Prot%20Coordination%20Technical%20Reference%20Document.pdf  Link in document corrected -LiveWire]

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 (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 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 and on Elements that connect a GSU transformer to the Transmission system and are used exclusively to export energy directly from a BES generating unit or generating plant.

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.

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 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 a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant, 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 implies ownership by the Generator Owner. Instead, this standard refers to these Facilities as “Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant” 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 are 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, and Figure 4 illustrates examples of Elements utilized in the aggregation of dispersed power resources that are in scope of the standard.

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. 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-025-2 using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant.

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-025-2 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 current- based, 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-025-2 standard using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant.

Since 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 are applicable to the standard, the loadability for relays applied on these Elements as shown in the shaded area of Figure 1 (i.e., CB102 and CB103) must be considered. If relay R2 or R3 is set with an element directional toward the transmission system (e.g., Buses B, C and D) or are non-directional, the relay would be affected by increased generator output in response to system disturbances and must meet the loadability setting criteria described in the standard. If relay R2 or R3 is set with an element directional toward the generator (e.g., Bus A), the relay would not be affected by increased generator output in response to system disturbances; therefore, the entity would not be required to apply the loadability setting criteria described in this standard.

PRC-005-2: 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. 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-025-2 using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant.

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-025-2 and an appropriate option for the application from Table 1 (e.g., Options 15a, 15b, 16a, 16b, 18, and 19) for phase overcurrent supervisory elements (i.e., phase fault detectors) associated with current- based, 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-025-2 standard using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant.

Since 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 are applicable to the standard, the loadability for relays applied on these Elements as shown in the shaded area of Figure 2 (i.e., CB102, CB103, CB104, and CB105) must be considered. If relay R2, R3, R4, or R5 is set with an element directional toward the transmission system (e.g., Buses B, C and D) or are non-directional, the relay would be affected by increased generator output in response to system disturbances and must meet the loadability setting criteria described in the standard. If relay R2, R3, R4, or R5 is set with an element directional toward the generator (e.g., Bus A), the relay would not be affected by increased generator output in response to system disturbances; therefore, the entity would  not  be required to apply the loadability setting criteria described  in  this standard.

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-025-2 using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant.

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 a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. 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.

This standard is also applicable to the UATs 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. The NERC System Protection and Control Subcommittee addressed low-side UAT protection in the document called Unit Auxiliary Transformer Overcurrent Relay Loadability During a Transmission Depressed Voltage Condition,[19. https://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/NERC%20-%20SPCS%20UAT%20-%20FEB_2016_final.pdf | Link Corrected – LiveWire] March 2016

 

Figure 4

Elements utilized in the aggregation of dispersed power producing resources (in some cases referred to as a “collector system” or “feeders”) consist of the Elements between individual generating units and the common point of interconnection to the Transmission system.

PRC-025-2: Figure-4: Elements utilized in the aggregation of dispersed power producing resources (DR)

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 steady- state 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 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 the line 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 other undesired behavior not occurred.

The dynamic load levels specified in Table 1 under column “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 relays associated with the facility are included in PRC-025.

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-025-2. Load- responsive 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-025-2. For example, feeder overcurrent relays and feeder step-up transformer overcurrent relays (see Figure 6) are included because these relays are challenged by generator loadability.

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 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 limiter functions 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.

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 at the remote end of the line or at the high-side of the GSU transformer (as prescribed by the Table 1 criteria). This can be simulated by means such as modeling the connection of a shunt reactor at the remote end of the line or at the GSU transformer high-side to lower the 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 at the relay location to calculate relay 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 (e.g., 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, which contributed 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 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 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 Considerations for 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 Overcurrent Relay (e.g., 50)

The 50 element is a non-directional overcurrent element that typically has no intentional time delay. The primary application is for close-in high current faults where high speed operation is required or preferred. The instantaneous overcurrent elements are subject to the same loadability issues as the time overcurrent elements referenced in this standard.

Phase Time Overcurrent Relay (e.g., 51)

See Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of this protection function. Note that the setting criteria established within the Table 1 options differ from the Considerations for  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 is a synchronous or asynchronous unit.

Phase Time Overcurrent Relay – Voltage-Restrained (e.g., 51V-R)

Phase time overcurrent voltage-restrained relays (e.g., 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 Chapter 2 of the Considerations for  Power Plant  and Transmission  System Protection  Coordination technical reference document for a detailed discussion of this protection function.

Phase Time Overcurrent Relay – Voltage Controlled (e.g., 51V-C)

Phase time overcurrent voltage-controlled relays (e.g., 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 Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of this protection function.

Phase Directional Overcurrent Relay – Directional Toward Transmission System (e.g., 67)

See Chapter 2 of the Considerations for 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 overcurrent relays is similar. Note that the setting criteria established within the Table 1 options differ from of the Considerations for 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 is a synchronous or asynchronous unit.

[For Table 1 options, example calculations, and other detailed appendices for this standard, please see the original PRC-025-2 document -LiveWire]

  1. Relays include low voltage protection devices that have adjustable settings.
  2. 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-025-2 Guidelines and Technical Basis for more detailed information concerning unit auxiliary transformers.
  3.  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).
  4. IEEE C37.102-2006, “Guide for AC Generator Protection,” Section 4.1.1.2.
  5. 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 de-energized 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.
  6. 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 de-energized 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.
  7. If the relay is installed on the high-side of the GSU transformer, use Option 14.
  8. If the relay is installed on the high-side of the GSU transformer, use Option 15.
  9. If the relay is installed on the high-side of the GSU transformer, use Option 16.
  10. If the relay is installed on the high-side of the GSU transformer, use Option 17.
  11. If the relay is installed on the high-side of the GSU transformer, use Option 18.
  12. . If the relay is installed on the high-side of the GSU transformer, use Option 19.
  13. If the relay is installed on the generator-side of the GSU transformer, use Option 7.
  14. If the relay is installed on the generator-side of the GSU transformer, use Option 8.
  15. If the relay is installed on the generator-side of the GSU transformer, use Option 9.
  16. If the relay is installed on the generator-side of the GSU transformer, use Option 10.
  17. If the relay is installed on the generator-side of the GSU transformer, use Option 11.
  18. If the relay is installed on the generator-side of the GSU transformer, use Option 12.

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