MOD-027-1: Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions

Purpose
To verify that the turbine/governor and load control or active  power/frequency control ¹  model and the model parameters, used in dynamic simulations that assess Bulk Electric System (BES) reliability, accurately represent generator unit real power response to system frequency variations.

Applicability
4.1. Functional entities

4.1.1 Generator Owner
4.1.2 Transmission Planner

4.2. Facilities For the purpose of the requirements contained herein, Facilities that are directly  connected to the Bulk Electric System (BES) will be collectively referred to as an “applicable unit” that meet the following:

4.2.1 Generation in the Eastern or Quebec Interconnections with the following characteristics:

4.2.1.1 Individual generating unit greater than 100 MVA (gross nameplate rating).

4.2.1.2 Individual generating plant consisting of multiple generating units that are directly connected at a common BES bus with total generation greater than 100 MVA (gross aggregate nameplate rating).

4.2.2 Generation in the Western Interconnection with the following characteristics:

4.2.2.1 Individual generating unit greater than 75 MVA (gross nameplate rating).

4.2.2.2 Individual generating plant consisting of multiple generating units that are directly connected at a common BES bus with total generation greater than 75 MVA (gross aggregate nameplate rating).

4.2.3 Generation in the ERCOT Interconnection with the following characteristics:

4.2.3.1 Individual generating unit greater than 50 MVA (gross nameplate rating).

4.2.3.2 Individual generating plant consisting of multiple generating units that are directly connected at a common BES bus with total generation greater than 75 MVA (gross aggregate nameplate rating).

Effective Date
5.1. For Requirements R1, and R3 through R5, the first day of the first calendar quarter beyond the date that this standard is approved by applicable regulatory authorities or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.  In those jurisdictions where regulatory approval is not required, the standard shall become effective on the first day of the first calendar quarter beyond the date this standard is approved by the NERC Board of Trustees, or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.

5.2. For Requirement R2, 30 percent of the entity’s applicable unit gross MVA for each Interconnection on the first day of the first calendar quarter that is four years following applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities, or in those jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter that is four years following NERC Board of Trustees adoption or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.

5.3. For Requirement R2, 50 percent of the entity’s applicable unit gross MVA for each Interconnection on first day of the first calendar quarter that is six years following applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities, or in those jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter that is six years following NERC Board of Trustees adoption or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.

5.4. For Requirement R2, 100 percent of the entity’s applicable unit gross MVA for each Interconnection on the first day of the first calendar quarter that is 10 years following applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities, or in those jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter that is 10 years following NERC Board of Trustees adoption or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.

Requirements
R1. Each Transmission Planner shall provide the following requested information to the Generator Owner within 90 calendar days of receiving a written request:  [Violation Risk Factor:  Lower] [Time Horizon:  Operations Planning]

• Instructions on how to obtain the list of turbine/governor and load control or active power/frequency control system models that are acceptable to the Transmission Planner for use in dynamic simulation,
• Instructions on how to obtain the dynamic turbine/governor and load control or active power/frequency control function model library block diagrams and/or data sheets for models that are acceptable to the Transmission Planner, or
• Model data for any of the Generator Owner’s existing applicable unit specific turbine/governor and load control or active power/frequency control system contained in the Transmission Planner’s dynamic database from the current (in-use) models.

R2. Each Generator Owner shall provide, for each applicable unit, a verified turbine/governor and load control or active power/frequency control model, including documentation and data (as specified in Part 2.1) to its Transmission Planner in accordance with the periodicity specified in MOD-027 Attachment 1.  [Violation Risk Factor:  Medium] [Time Horizon:  Long-term Planning]

2.1. Each applicable unit’s model shall be verified by the Generator Owner using one or more models acceptable to the Transmission Planner.  Verification for individual units rated less than 20 MVA (gross nameplate rating) in a generating plant (per Section 4.2.1.2, 4.2.2.2, or 4.2.3.2) may be performed using either individual unit or aggregate unit model(s) or both.  Each verification shall include the following:

2.1.1. Documentation comparing the applicable unit’s MW model response to the recorded MW response for either:

• A frequency excursion from a system disturbance that meets MOD-027 Attachment 1 Note 1 with the applicable unit on-line,
• A speed governor reference change with the applicable unit online, or
• A partial load rejection test, ²

2.1.2. Type of governor and load control or active power control/frequency control³ equipment,

2.1.3. A description of the turbine (e.g. for hydro turbine – Kaplan, Francis, or Pelton; for steam turbine – boiler type, normal fuel type, and turbine type; for gas turbine – the type and manufacturer; for variable energy plant – type and manufacturer),

2.1.4. Model structure and data for turbine/governor and load control or active power/frequency control, and

2.1.5. Representation of the real power response effects of outer loop controls (such as operator set point controls, and load control but excluding AGC control) that would override the governor response (including blocked or nonfunctioning governors or modes of operation that limit Frequency Response), if applicable.

R3. Each Generator Owner shall provide a written response to its Transmission Planner within 90 calendar days of receiving one of the following items for an applicable unit.

• Written notification, from its Transmission Planner (in accordance with Requirement R5) that  the turbine/governor and load control or active power/frequency control model is not “usable,”
• Written comments from its Transmission Planner identifying technical concerns with the verification documentation related to the turbine/governor and load control or active power/frequency control model, or
• Written comments and supporting evidence from its Transmission Planner indicating that the simulated turbine/governor and load control or active power/frequency control response did not approximate the recorded response for three or more transmission system events.

The written response shall contain either the technical basis for maintaining the current model, the model changes, or a plan to perform model verification ⁴  (in accordance with Requirement R2).  [Violation Risk Factor:  Lower] [Time Horizon:  Operations Planning]

R4. Each Generator Owner shall provide revised model data or plans to perform model verification⁵  (in accordance with Requirement R2) for an applicable unit to its Transmission Planner within 180 calendar days of making changes to the turbine/governor and load control or active power/frequency control system that alter the equipment response characteristic⁶ .  [Violation Risk Factor:  Lower] [Time Horizon:  Operations Planning]

R5. Each Transmission Planner shall provide a written response to the Generator Owner within 90 calendar days of receiving the turbine/governor and load control or active power/frequency control system verified model information in accordance with Requirement R2 that the model is usable (meets the criteria specified in Parts 5.1 through 5.3) or is not usable.

5.1. The turbine/governor and load control or active power/frequency control function model initializes to compute modeling data without error,

5.2. A no-disturbance simulation results in negligible transients, and

5.3. For an otherwise stable simulation, a disturbance simulation results in the  turbine/governor and load control or active power/frequency control model exhibiting positive damping.

If the model is not usable, the Transmission Planner shall provide a technical description of why the model is not usable.  [Violation Risk Factor:  Medium] [Time Horizon:  Operations Planning]

Measures 
M1. The Transmission Planner must have and provide the dated request for instructions or data, the transmitted instruction or data, and dated evidence of a written transmittal (e.g., electronic mail message, postal receipt, or confirmation of facsimile) as evidence that it provided the request within 90 calendar days in accordance with Requirement R1.

M2. The Generator Owner must have and provide dated evidence it verified each generator turbine/governor and load control or active power/frequency control model according to Part 2.1 for each applicable unit and a dated transmittal (e.g., electronic mail message, postal receipt, or confirmation of facsimile) as evidence it provided the model, documentation, and data to its Transmission Planner, in accordance with Requirement R2.

M3. Evidence for Requirement R3 must include the Generator Owner’s dated written response containing the information identified in Requirement R3 and dated evidence of transmittal (e.g., electronic mail message, postal receipt, or confirmation of facsimile) of the response.

M4. Evidence for Requirement R4 must include, for each of the Generator Owner’s applicable units for which system changes specified in Requirement R4 were made, dated revised model data or dated plans to perform a model verification and dated evidence of transmittal (e.g., electronic mail message, postal receipt, or confirmation of facsimile) within 180 calendar days of making changes.

M5. Evidence of Requirement R5 must include, for each model received, the dated response indicating the model was usable or not usable according to the criteria specified in Parts 5.1 through 5.3 and for a model that is not useable, a technical description is the model is not usable, and dated evidence of transmittal (e.g., electronic mail messages, postal receipts, or confirmation of facsimile) that the Generator Owner was notified within 90 calendar days of receipt of model information in accordance with Requirement R5.

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Requirement Number and Text of Requirement
Rl. When the actual power flow exceeds an SOL for a Transmission path, the Transmission Operators shall take immediate action to reduce the actual power flow across the path such that at no time shall the power flow for the Transmission path exceed the SOL for more than 30 minutes.
Question:
APS asks for clarification that the Requirement Rl applies "to Transmission Operators, as defined in the NERC Glossary of Terms, and not to the path operators who have no compliance responsibilities under TOP-007-WECC-l (TOP), other than any responsibilities they may have as a Transmission Operator for facilities in their respective Transmission Operator Areas." (Emphasis added.)
Response:
APS' Request is governed by the Procedures, Step 3 - Drafting Team Begins Drafting Phase and Submits Draft Standard to WSC, at page 6, stating: "All WECC Standards will follow a standard format that refers to the "Responsible Entities" included in the NERC Functional Model and includes compliance measures according to the WECC standard template." (Emphasis added.) The NERC Functional Model 4, in effect at the time the standard was drafted, did not include Path Operators as an approved applicable entity; therefore, the document only applies to the stated Transmission Operators and does not apply to Path Operators. Neither the TOP's predecessor document, TOP-STD-007-0, Operating Transfer Capability, nor TOP- 007-WECC-l, System Operating Limits, lists the Path Operator as an applicable entity. Both list the Transmission Operator. Even though TOP-STD-007-0 referred to an Operating Agent in the column header of its Attachment A, that reference did not impose a task or responsibility on a Path Operator nor did its reference change the applicability of the document to any entity other than the Transmission Operator. During the development of TOP-STD-007-0, the drafting team acknowledged that certain tasks were generally being performed by Path Operators; however, the Procedures prohibited assigning tasks to a Path Operator because the Path Operator is not "included in the NERC Functional Model."