PRC-025-1: Generator Relay Loadability

Purpose

To set load-responsive generator protective relays at a level such that  generators do not trip during system disturbances that are not damaging to the generator thereby unnecessarily removing the generator from service.

Applicability

3.1. Functional Entities:

3.1.1 Generator Owner that applies load-responsive protective relays on  Facilities listed in 3.2, Facilities.

3.2. Facilities:  The following Elements of the Bulk Electric System generation Facilities, including those 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 Auxiliary transformer(s) that supply overall auxiliary power necessary to keep generating unit(s) online. 1

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.

Requirements and Measures 

 R1. Each Generator Owner shall install settings that are in accordance with PRC-025-1 – Attachment 1:  Relay Settings, on each load-responsive protective relay while  maintaining reliable  protection.  [Violation Risk Factor:  High] [Time Horizon:  Long-Term Planning]

M1. For each load-responsive protective relay in accordance with PRC-025-1 – Attachment 1:  Relay Settings, each Generator Owner shall have and provide as evidence, dated documentation of: (1) settings calculations, and (2) that settings were installed.

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 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.


 

PRC-025-1 – Attachment 1:  Relay Settings 

Each Generator Owner that applies load-responsive protective relays shall use one of the following Options 1-17 in Table 1, Relay  Loadability Evaluation Criteria (“Table 1”), to set each load-responsive protective relay according to its application.  The bus voltage is determined by the criteria for the various applications listed in Table 1.

Synchronous generator output pickup setting criteria values are determined by the unit’s maximum seasonal gross Real Power capability, in megawatts (MW), as reported to the Planning Coordinator; and the unit’s Reactive Power capability, in megavoltampere-reactive (Mvar), is determined by calculating the rated MW based on the unit’s nameplate megavoltampere (MVA) at rated power factor.

Asynchronous generator output pickup setting criteria values are determined by the site’s aggregate maximum seasonal gross Real Power capability, in MW, as reported to the Planning Coordinator; and the Reactive Power capability, in (Mvar), as determined by calculating the rated Mvars based on the aggregate MVA at rated power factor and adding the Mvar output of any static or dynamic reactive power devices.  Asynchronous generator criteria also include inverter-based installations.

Relay TypeOptionApplicationBus VoltagePickup Setting Criteria
Phase Distance Relay (21) - Directional toward the Transmission System1Synchronous generatorsGenerator bus voltage corresponding to 0.95 per unit of the high- side nominal voltage times the turns ratio of the generator step-up transformerThe impedance element shall be set less than the impedance derived from 115% of:

(1) Real Power output - 100% of maximum seasonal gross MW reported to the Planning Coordinator, and

(2) Reactive Power output - a value that equates to
150% of rated MW
Phase Distance Relay (21) - Directional toward the Transmission System2Synchronous generatorsCalculated 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 impedance derived from 115% of:

(1) Real Power output - 100% of maximum seasonal gross reported to the Planning Coordinator, and

(2) Reactive Power output - a value that equates to
150% of rated MW
Phase Distance Relay (21) - Directional toward the Transmission System3Synchronous generatorsSimulated 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 impedance derived from 115% of:

(1) Real Power output - 100% of maximum seasonal gross MW reported to the Planning Coordinator, and

(2) Reactive Power output - a value that equates to the Maximum Mvar output determined by simulation
Phase Distance Relay (21) - Directional toward the Transmission System4Asynchronous generators (including inverter- based installations)Generator bus voltage corresponding to 1.0 per unit of the high- side nominal voltage times the turns ratio of the generator step-up transformerThe impedance element shall be set less than the impedance derived from 130% of the total aggregate MVA output at rated power factor
Phase Time Overcurrent Relay (51V) voltage- restrained5Synchronous generatorsGenerator bus voltage corresponding to 0.95 per unit of the high- side nominal voltage times the turns ratio of the generator step-up transformerThe overcurrent element shall be set greater than the calculated current derived from 115% of:

(1) Real Power output - 100% of maximum seasonal gross MW reported to the Planning Coordinator, and

(2) Reactive Power output - a value that equates to
150% of rated MW
Phase Time Overcurrent Relay (51V) voltage- restrained6Synchronous generatorsCalculated 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 the calculated current derived from 115% of:

(1) Real Power output - 100% of maximum seasonal gross MW reported to the Planning Coordinator, and

(2) Reactive Power output - a value that equates to
150% of rated MW
Phase Time Overcurrent Relay (51V) voltage- restrained7Synchronous generatorsSimulated 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 the calculated current derived from 115% of:

(1) Real Power output - 100% of maximum seasonal gross MW reported to the Planning Coordinator, and

(2) Reactive Power output - a value that equates to
Maximum Mvar output determined by simulation
Phase Time Overcurrent Relay (51V) voltage- restrained8Asynchronous generators (including inverter- based installations)Generator bus voltage corresponding to 1.0 per unit of the high- side nominal voltage times the turns ratio of the generator step-up transformerThe overcurrent element shall be set greater than the current derived from 130% of total aggregate MVA output at rated power factor
Phase Time Overcurrent Relay (51C) - Enabled to operate as a function of voltage (e.g., Voltage controlled relay)9Synchronous or asynchronous generators (including inverter installations)Generator bus voltage corresponding to 1.0 per unit of the high- side nominal voltage times the turns ratio of the generator step-up transformerVoltage control setting shall be set less than 75%
of the nominal generator bus voltage
Phase Time Overcurrent Relay (51)10Generator step-up transformer - Synchronous generators0.85 per unit of the high-side nominal voltageThe element shall be set greater than the calculated current derived from 115% of:

(1) Real Power output - 100% of connected generation reported, and

(2) Reactive Power output - a value that equates to
150% of connected generation rated MW
Phase Time Overcurrent Relay (51)11Generator step-up transformer - Synchronous generators0.85 per unit of the high-side nominal voltageThe element shall be set greater than the calculated current derived from 115% of:

(1) Real Power output - 100% of connected generation reported, and

(2) Reactive Power output - a value that equates to the Maximum Mvar output determined by simulation
Phase Time Overcurrent Relay (51)12Generator step-up transformer - Asynchronous generators only (including inverter- based installations)0.85 per unit of the high-side nominal voltageThe element shall be set greater than the calculated current derived from 130% of aggregate installed maximum rated MVA output of the connected generators at rated power factor
Phase Distance Relay (21) - Directional toward the Transmission System13Generator step-up transformer - Synchronous generatorsGenerator bus voltage corresponding to 0.95 per unit of the high- side nominal voltage times the turns ratio of the generator step-up transformerThe impedance element shall be set less than the impedance derived from 115% of:

(1) Real Power output - 100% of connected generation reported, and

(2) Reactive Power output - a value that equates to
150% of connected generation rated MW
Phase Distance Relay (21) - Directional toward the Transmission System14Generator step-up transformer - Synchronous generatorsCalculated 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 impedance derived from 115% of:

(1) Real Power output - 100% of connected generation reported, and

(2) Reactive Power output - a value that equates to
150% of rated MW
Phase Distance Relay (21) - Directional toward the Transmission System15Generator step-up transformer - Synchronous generatorsSimulated 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 impedance derived from 115% of:

(1) Real Power output - 100% of connected generation reported, and

(2) Reactive Power output - a value that equates to the Maximum Mvar output determined by simulation
Phase Distance Relay (21) - Directional toward the Transmission System16Generator step-up transformer - Asynchronous generators (including inverter- based installations)Generator bus voltage corresponding to 1.0 per unit of the high- side nominal voltage times the turns ratio of the generator step-up transformerThe impedance element shall be set less than the impedance derived from 130% of the total aggregate MVA output at rated power factor
Phase Time Overcurrent Relay3 (51)17Auxiliary transformers1.0 per unit nominal voltage on the high- side terminals of the auxiliary transformerThe element shall be set greater than the calculated current derived from 150% of the current derived from the auxiliary transformer nameplate
maximum MVA rating

 

  1.   These transformers are variably referred to as station power, unit auxiliary, 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 Guidelines and Technical Basis for more detailed information concerning auxiliary transformers.
  2. 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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