i

MISO MOD-033-1 Model

Validation Process Version 1.2

November 13, 2019

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DOCUMENT REVISION HISTORY

Changes (additions, modifications, deletions) made to this document are recorded in the table

below.

Revision date Version, Section & Title

Summary of Changes

Authors Approver

June 27, 2017 Version 1.0 Initial version Nihal Mohan, Cody Doll

David Duebner

August 14, 2018 Version 1.1 Update Area Interchange requirement Update Load Mapping Process

Matthew Ladd Amanda Schiro

Nov. 13, 2019 Version 1.2 Updated Branch Flow requirements

Matthew Ladd Amanda Schiro

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Contents

a) Purpose ............................................................................ Error! Bookmark not defined.

b) Scope of validation ........................................................... Error! Bookmark not defined.

1 R1.1 Power Flow Model Validation ..................................................................................... 3

1.1 Select a scenario ......................................................................................................... 5

1.2 Data Acquisition ........................................................................................................... 5

1.3 Adjust Planning Case to Match S.E. Case ................................................................... 5

1.4 Evaluate model performance per R1.3 guidelines ........................................................ 7

1.5 Resolve differences per R1.4 guidelines ...................................................................... 7

1.6 Document the power flow model validation .................................................................. 7

2 R1.2 Dynamics Model Validation ........................................................................................ 8

2.1 Selection of Local Dynamic Event ...............................................................................10

2.2 Data Acquisition ..........................................................................................................10

2.3 Prepare a dynamic model and simulate event .............................................................11

2.4 Evaluate dynamic model performance per R1.3 guidelines .........................................11

2.5 Resolve differences per R1.4 guidelines .....................................................................11

2.6 Document the model validation ...................................................................................11

3 R1.3 Guidelines to use to determine unacceptable differences in performance under R1.1

and R1.2 ...................................................................................................................................12

4 R1.4 Guidelines to resolve unacceptable differences .........................................................13

4.1 Applicable NERC Standards .......................................................................................14

5 Data acquisition from RC and TOP per requirement R2 .....................................................16

Appendix A. Case Preparation and Sanity Checks Guidelines .............................................17

Appendix B. Contacts for obtaining information and data .....................................................18

Appendix C. NERC Standard References ............................................................................21

NERC Standard MOD-026-1 .................................................................................................21

NERC Standard MOD-027-1 .................................................................................................21

NERC Standard MOD-032-1 .................................................................................................22

NERC Standard IRO-010-2 ...................................................................................................22

Appendix D. Sample Request for Verification .......................................................................24

Appendix E. Reference Documents ......................................................................................25

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Introduction Pursuant to requirement R1 of MOD-033-1, this document describes MISO’s model data validation process. There are five sections in this document describing in detail the following requirements per MOD-033-1 standard:

Section 1: describes MISO’s process for performing R1.1 comparison of the performance of planning power flow model to actual system behavior.

Section 2: describes MISO’s process for performing R1.2 comparison of the performance of planning dynamic model to actual system behavior.

Section 3: describes the guidelines MISO shall use to determine unacceptable differences in model performance per part R1.3 of the MOD-033-1 standard.

Section 4: describes process which MISO shall use to resolve the unacceptable differences to fulfill requirement R1.4.

Section 5: describes process which MISO shall follow to obtain data from Reliability Coordinators (RC) and Transmission Operators (TOP) per requirement R2.

A high level overview of MOD-033 overall process is described below:

Figure 1-1 High level overview of MOD-033 process

The scope of validation is limited to MISO’s Planning Coordinator (PC) functional area. MISO will select dynamic local events for validation based on criterion described in Section 2. A list of quantities which shall be used for validation purposes are described in Section 3. MISO shall notify the equipment owners in MISO of model performance issues; to correct the component model is the responsibility of the model data owner, as described in Section 4. Model performance issues caused by model data outside of MISO’s planning coordinator area will be identified though resolution of those model data issues is outside of scope. MISO may provide model concerns to external parties for their consideration.

• Obtain real time data (R2)

Select a scenario

• Section 1 and 2 (R1.1,R1.2)

Prepare models, run simulations

• Section 3(R1.3)

Evaluate model performance

• Section 4(R1.4)

Address differences

Stop

Start

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1 R1.1 Power Flow Model Validation

Per part 1.1 of requirement R1, this section documents the process to compare the performance

of steady state planning model to actual system behavior.

R1.1. Comparison of the performance of the Planning Coordinator’s portion of the existing system in a planning power flow model to actual system behavior, represented by a state estimator case or other Real-time data sources, at least once every 24 calendar months through simulation;

A high level overview of the process is shown in Figure 1-1 Power flow model validation. The

Planning Coordinator swim lane on top describe the tasks performed by MISO as a planning

coordinator and the swim lanes below describes data to be provided by MISO as an RC and the

TOPs tasks per requirement R2 of the standard. As stated in R1.1 MISO will perform this

comparison at least once every 24 months.

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Figure 1-1 Power flow model validation

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1.1 Select a scenario

For steady state model validation per part R1.1, MISO shall validate a summer peak

planning model utilizing State Estimator (S.E.) data for the system peak loading condition

or near peak loading condition.

1.2 Data Acquisition

1. Obtain Planning Model: request Outage Coordination group to provide Outage

Coordination Daily Base case (OCDB) for summer peak day. There are several

advantages of using Outage coordination daily base case planning model. It is

developed from Model On Demand (MOD) planning model database with relevant

projects applied and known outages for MISO and external entities modeled. The Load

and Generation profiles are obtained from NERC SDX system, which more closely

match S.E. model. These models are internally vetted through multiple reviews.

2. Obtain State Estimator model: request EMS Network Modeling group to provide the

State Estimator model for the system condition being studied.

3. Obtain Equipment Mapping Sources: Obtain S.E. model to planning model mapping.

The IDC and MISO commercial node mapping (EP node mapping) to map S.E. case to

planning case posted on EMS model section on MISO extranet can be used.1

1.3 Adjust Planning Case to Match S.E. Case

1. Area Names Mapping: MOD planning base case may utilize different area names for

some entities compared to S.E. case. The area names are mapped to resolve

differences. The planning case has area names changed to match S.E. case.

2. Generation dispatch: Utilizing the mapping sources, generation dispatch in planning

model should be modified to match the system conditions from real-time data sources.

3. Load: Map Loads based on bus number from the S.E.2 to same bus number in Planning

Case. For the Loads that do not match bus numbers map them to the nearest Planning

bus. Incorporate known qualifying facility loads and station service loads that are not

represented.

The approach for mapping load and generation is shown in Figure 1-2. For all the buses

which exist in both Planning and S.E. models (mapped buses), perform scaling on individual

bus levels so that bus level values match. Perform scaling such that following equations

1 https://extranet.misoenergy.org/EMSModels/Pages/EMSModels.aspx . NDA and access privileges required. 2 Pay attention to pseudo-injections of loads at buses for solution convergence by S.E software. If S.E. solution is not realistic, contact EMS Modeling. Data from other real-time sources such as PI historian or SCADA may also be used.

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hold true on area level. If necessary, individual substation load and generation values may

be adjusted:2

Total in Planning Model = B+C MW/ Mvar4

A = C MW/Mvar3

Where:

A = Sum total of unmapped quantity in Planning Model

B = Sum total of mapped quantity in Planning Model and S.E. model

C = Sum total of unmapped quantity in S.E. model

Figure 1-2 MISO Load and Gen mapping approach

4. Generator scheduled voltage: The generator scheduled voltage in planning case

should be adjusted to match the EMS case.

5. Transformer tap positions (fixed and adjustable): Adjustable LTC transformer taps in

the planning case may be adjusted to match the EMS case. Fixed taps cannot be

adjusted automatically or remotely and are rarely moved. The position/status of these

fixed taps should be compared and any differences found should be noted and resolved.

6. Switched shunts status/position: Switched shunts in planning model should be

adjusted to match the EMS case. The position/status of fixed shunts, that cannot switch

on or off automatically and are not remotely controlled by an operator, should be

compared and any differences noted and resolved.

7. Area interchange: Validate that the flows on all MISO LBA and BA Tie-lines between

the State Estimator case and the PSS/e powerflow are within the toleration requirements

for line flow as designated in Section 3.

2 Python script “MOD33MappingTool.py” developed by System Modeling for initial mapping may be used. 3 For generator mapping, only MW amounts are matched.

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8. Manual case adjustments: Set the HVDC schedules in planning model for GRE Coal

Creek, Square Butte, Manitoba Hydro HVDC links and Mackinaw VSC based on S.E.

model.4 Adjust Minnesota Power’s industrial large motor loads5 that are modeled as

generators in planning case.

9. Model outage facilities consistently: The facility outages in S.E. case need to be

applied to be the planning case. If starting planning model is not an Outage

Coordination Daily case, then Control Room Operation Window (CROW) outages may

be requested from Outage Coordination group.

10. Perform model tuning and sanity checks: The planning model should be solved and

reviewed to obtain satisfactory performance. If there are any major issues6 identified,

responsible groups should be contacted to resolve the issues. For example, differences

in transmission lines and transformer topology should be resolved. Contact Real Time

Operations, EMS modeling to compare planning assumptions and operating practices

for bus splits, normally open switches, radial lines, etc. Differences in topology will be

reviewed. Differences due to Node-Breaker vs. Bus-Branch in planning do not need to

be resolved.

1.4 Evaluate model performance per R1.3 guidelines The guidelines for evaluating model performance are described in Section 3.7 It is important to

note that engineering judgment must be used in application of the guidelines.

1.5 Resolve differences per R1.4 guidelines If portions of the planning model are found outside the guidelines specified in R1.3, follow the

guidelines per Section 4 to resolve the differences.

1.6 Document the power flow model validation Results and communications for R1.4 and R2 will be documented. Differences in model

parameters that were identified in the previous steps will be documented, if they are expected to

be accurately represented in the planning case. Some items may vary slightly due to differences

between node-breaker modeling and bus-branch modeling that do not need to be reconciled as

they are electrically equivalent.

4 Step number 5 can be omitted for dynamic event validation, if the event is far from these regions. Note that mapping HVDC and VSC equipment can cause solution convergence issues. 5 Refer MOD-033 mapping workbook “MOD-033_EMS to IDC Equipment Mapping.xlsx” to perform manual adjustments. 6 Attention should be paid to the list of issues are identified in 0, during application of guidelines. 7 Can utilize Python based script “MISOModelValidation_100416.py” for model review to evaluate the quantities.

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2 R1.2 Dynamics Model Validation

Per part 1.2 of requirement R1, this section documents the process to compare performance of

dynamic planning model to actual system behavior.

R1.2. Comparison of the performance of the Planning Coordinator’s portion of the existing system in a planning dynamic model to actual system response, through simulation of a dynamic local event, at least once every 24 calendar months (use a dynamic local event that occurs within 24 calendar months of the last dynamic local event used in comparison, and complete each comparison within 24 calendar months of the dynamic local event). If no dynamic local event occurs within the 24 calendar months, use the next dynamic local event that occurs;

This section describes the process for dynamic model validation in detail. A high level summary

of the methodology is as following: select suitable event(s) against which system model

response will be validated; determine what real-time measurement information is available such

as Phasor Measurement Unit (PMU) or Dynamic Disturbance Recorder data; Obtain real time

pre-contingency event conditions and prepare a steady state model by following procedure laid

out in Section 1.3. Thereafter perform dynamic model validation. As stated in R1.2 MISO will

perform this comparison at least once every 24 months.

The dynamic model validation process is show in Figure 2-1 below.

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Figure 2-1 R1.2 Dynamic model validation process

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2.1 Selection of Local Dynamic Event The following dynamic events shall be considered.

1. Transmission system faults– three-phase, single-phase, multi-phase, normal or delayed

clearing, or other low voltage conditions on the transmission elements, including lines or

autotransformers

2. Transmission line switching (including opening and closing) without a fault

3. Generating unit(s) tripping or oscillating

4. HVDC tripping or run backs

5. AC or DC controls (mis)operations

6. Planned or unexpected large load tripping, load shedding

7. Large FACTS device switching, failure, or operation

8. System islanding or loss of synchronism

9. Other large system swings exhibiting voltage or frequency fluctuations, particularly with

low damping ratio and high amplitude

10. Large system events with significant changes in frequency, voltage or MW values.

Event selection will depend on availability of proper disturbance monitoring/recording data.

Following event types which are not suitable for MOD-033-1 validation due to limitations in the

simulation tools will not be selected:

1. Asymmetric events such as sustained unbalanced flows such as single pole reclosing

2. An event that occurred at the top of the hour when generating units are ramping up or

down. In study simulation, during the initialization process, it is assumed that all

generating units are static with fixed outputs, but over the course of the simulation

timeframe which typically lasts 60 to 120 seconds, some of the units may ramp up or

down.

2.2 Data Acquisition Once a dynamic local event is selected, the following data may be acquired:

Data that should be acquired:

1. S.E. pre-contingency case from MISO EMS modeling

2. Sequence of event logs from Real Time Operations, Transmission Operators

3. PMU recordings for the event from Real Time Operations or Dynamic Disturbance

Recording data

4. MISO dynamic data files from System Modeling group

Optional data may be acquired when necessary:

1. PI historian data, SCADA information, Frequency Response Tool data8

2. OCDB planning case for event date from Outage Coordination group

Refer Appendix B for details on contact information.

8 PI historian, SCADA data, Frequency Response Tool Data to be acquired if necessary, for example model validation for frequency excursion event.

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2.3 Prepare a dynamic model and simulate event 1) Set up the power flow case as described above in Section 1. The planning power flow

case will be prepared to represent the pre-disturbance system representation.

2) Obtain MISO dynamic data and prepare dynamic model: Post development of the

power flow model, obtain latest MTEP model dynamic data and prepare a dynamic

model.

3) Creation of Sequence of Events File: Prepare a dynamic disturbance file which

adequately describes the sequence of events.

4) Create channels for monitoring the quantities: proper quantities (such as MW and

Mvar out of a generating unit, Mvar output of a dynamic reactive device, MW and/or

Mvar flows, frequency on a transmission element, voltage magnitudes at major buses)

should be monitored when setting up the dynamic simulation.

5) Run the dynamic simulation: run dynamic simulation duration for 10 to 20 seconds.

For longer duration dynamic simulations slow acting responses from devices such as

AGC, tap-changers, capacitor responses would need to be accounted for.

2.4 Evaluate dynamic model performance per R1.3 guidelines Once the simulation has been run, a comparison of the dynamic simulation results to the actual

dynamic system event data will be made. For details on the parameters to compare and what is

acceptable performance of this comparison, see Section 3. It is important to note that

engineering judgment must be applied in application of the guidelines. Sample buses, branches

close to event location should be selected for application of these guidelines.

2.5 Resolve differences per R1.4 guidelines If the planning model performance does not compare to actual system behavior per R1.3

guidelines, follow the guidelines per Section 4 to resolve the differences.

2.6 Document the model validation Charts, results, communications for R1.4 and R2 will be documented. Differences in model

simulations that were identified in the previous steps will be documented. Dynamic model

validation will focus on system near the dynamic local event.

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3 R1.3 Guidelines to use to determine

unacceptable differences in performance

under R1.1 and R1.2

This section describes guidelines which MISO will use to determine unacceptable differences

per part 1.1 and 1.2 of requirement R1.

R1.3 Guidelines the Planning Coordinator will use to determine unacceptable differences in performance under Part 1.1 or 1.2; and

MISO will use engineering judgment to evaluate planning model performance. To facilitate the

evaluation, MISO will use review teams comprised of Subject Matter Experts (SME) and

management to decide when performance outside the guidelines are acceptable. Table 3-1 lists

guidelines which will be used to determine differences in performance for the steady-state

model validation (R1.1) that require review. MISO may choose some of the parameters from

Table 3-1 in for evaluation of model performance. The items in Table A-1 should be considered

for case preparation of the model during the application of the R1.3 guidelines.

Table 3-1 provides evaluation criterion, both for percentage differences and absolute differences

for the real and reactive power flows to be applied on major transmission facilities as

determined by PC. For bus voltages, per unit values will be compared on a percentage basis.

For example, 1.02 p.u. in S.E. model, 0.98 pu in planning model is 4% difference. Loadings may

be compared on percentage difference or an absolute difference. The reference for difference

calculation is real-time data source. For nonzero impedance lines, the branch flow can

normalized based on branch normal continuous ratings (Rate A) and % difference should be

examined. For example, a line rated for 845 MVA loaded at 211 MVA in S.E. case is at 25%

normal continuous ratings and same circuit loaded at 279 MVA in Planning case is at 33% of

the normal continuous ratings. The difference in percentage normal loading is equal to 8%. This

matrix is capable of accounting the combined impact of real and reactive flows on the line,

irrespective of line normal ratings and kV class.

Quantity Acceptable Differences

Bus voltage magnitude ±2% (>346 kV) ±3% (200>kV>345kV) ±4% (100>kV>199kV)

Generating Bus voltage magnitude ±2%

MVA Current flow ±10% or ±100 MVA (>300kV) ±10% or ±80 MVA (200>kV>300kV) ±10% or ±60 MVA (100>kV>199kV)

Difference in % normal loading ±10% on branch normal continuous rating

Table 3-1 Guidelines to identify acceptable differences between simulated and real time data for steady state validation

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Dynamic model performance guidelines: In accordance with NERC MOD-033 application

guidelines,9 to determine the unacceptable dynamic model performance, MISO will plot the

simulation result on the same graph as the actual system response, and the two plots will be

given a visual inspection to see if they look similar or not. MISO subject matter experts (SME)

will determine if the model performance is acceptable.

4 R1.4 Guidelines to resolve unacceptable

differences

Per requirement R1.4, each Planning Coordinator must have guidelines to resolve the

unacceptable differences in performance between the power flow model to actual system

behavior or existing system planning dynamic model to actual system response. MISO shall

utilize applicable NERC MOD Standards, IRO-010 standard and MISO tariff provisions to ask

equipment and data owners to resolve differences. This section describes process through

which MISO shall use to determine unacceptable differences per part 1.3 per requirement R1.4.

A high level process for R1.4 is described in Figure 4-.

R1.3. Guidelines to resolve the unacceptable differences in performance identified under Part 1.3

9 “Guidelines for the dynamic event comparison may be less precise. Regardless, the comparison should indicate

that the conclusions drawn from the two results should be consistent. For example, the guideline could state that the simulation result will be plotted on the same graph as the actual system response. Then the two plots could be given a visual inspection to see if they look similar or not”, page 9 of 11, MOD-033 application guidelines

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Figure 4-1 R1.4 process to resolve unacceptable differences

4.1 Applicable NERC Standards Model or equipment

Applicable NERC Standard, Document

Comment

Steady state model

MOD-032 IRO-010

NERC MOD-032 enables for the Planning Coordinator to call

for reviews of steady state and dynamic data as listed in

Attachment 1 of the standard. NERC MOD-032 applies to

generators that meet the NERC registration criteria under the

Bulk Electric System definition (i.e. greater than 20 MVA for a

single unit or greater than 75 MVA aggregate generation

connected at 100 kV or above).

MISO as Reliability Coordinator shall use applicable provisions of IRO-010 to obtain data required for data validation.

Per R1.3 evaluations, MISO will send out letter to data owner

citing the issue

Data owner to review the information,

determine corrections

•TP to contact GO if issues found in generator model. Cite MOD-026 for exciter, MOD-027 for governor issue, MOD-032 for other issues

•GO to review information, perform model correction or validation if required. Interim model can be provided by GO, if GO needs time perform model validation

Data owner responds to MISO

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Dynamic Model

MOD-032

MISO will requests dynamic model updates made with

reference to MOD-032 to concerned TP. TP should contact

GO and references to MOD-026 or MOD-027 while requesting

model updates.10

Table 4-1 Applicable NERC Standards resolving unacceptable differences

10 MISO is not registered as Transmission Planner (TP) for NERC MOD-026 and MOD-027. The TP

under MISO PC function should exercise NERC MOD-026 and MOD-027 provisions. NERC MOD-026

requires the Generator Owner to verify generator excitation system or plant volt/var control function

models and the parameters used in simulations for the Transmission Planner. When simulations do not

match actual real time data then the Transmission Planner, under Requirement R3 can request that the

Generator Owner verify the excitation system model and parameters. The Generator Owner must then

provide a written response with the technical basis for maintaining the current model, model changes or a

plan to provide verification in accordance with the standards R2 requirement. NERC standard MOD-027

is similar to MOD-026 except that it requires verification of the governor and associated functions.

Under NERC MOD-026 and MOD-027, Generator Owners may have a long term plan to validate models. In many cases it will be better to use an “interim model” based on a parameter update that can be determined from disturbance data. NERC MOD-026 and MOD-027 Requirement R2 support the use of measured system disturbance data to provide interim parameters for the model.

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5 Data acquisition from RC and TOP per

requirement R2

Requirement R2 of MOD-033 requirement states:

R2. Each Reliability Coordinator and Transmission Operator shall provide actual system behavior data (or a written response that it does not have the requested data) to any Planning Coordinator performing validation under Requirement R1 within 30 calendar days of a written request, such as, but not limited to, state estimator case or other Real-time data (including disturbance data recordings) necessary for actual system response validation.

MISO is NERC registered Reliability Coordinator, Transmission Operator and Planning Coordinator. Requirement R1 shall be performed by MISO planning coordinator and requirement R2 shall be fulfilled by RC and applicable TOP members. MISO Planning has identified the sources of information required for steady state and dynamic model validation and described them in Sections 1 and 2 and will request data from referenced departments, as necessary. The contact information for referenced departments is mentioned in Appendix B. Data Required for Provided by Format

EMS S.E. case Steady State Validation MISO EMS Modeling PSSE .raw format

PI Historian Data Steady State Validation, Dynamic Validation

MISO Real Time Engineering Support

Importable in Microsoft Excel

EMS to Planning Mapping

Mapping the topology, load, generation and other quantities

EMS Modeling MISO Text, Microsoft Excel, PDF

Frequency Response Tool Score Card

Dynamic Model Validation

MISO Shift Operations Microsoft Excel

Synchrophasor Data Dynamic Model Validation

MISO Real Time Engineering Support, TOP in MISO Regions

Per unit, Positive sequence data , Text, CSV or Microsoft Excel11

Dynamic DR/ DFR data12

Dynamic Model Validation

TOP in MISO Regions Per unit, Positive sequence data13

Sequence of Event Dynamic Model Validation, Steady State Validation

MISO RC, TOP in MISO Regions

Log files, text, email.

Outage Information Steady State Validation , Dynamic Model Validation

MISO Outage Coordination group (CROW)

Outages Mapped to PSSE models

Outage Coordination Daily Base case

Steady State Validation , Dynamic Model Validation

PSSE .raw or .sav format

Table 5-1 list of data required from RC and TOP

End of procedure. Reference materials provided in Appendices.

11 If positive sequence data is not available, then MISO would require the process and information to convert it in positive sequence 12 If available with TOP and RC

MISO 17

Appendix A. Case Preparation and Sanity Checks Guidelines

The items in Table A-1 should be considered for case preparation of the model during the

application of the R1.3 guidelines.

Dynamic model preparation

Dynamic model check

Perform sanity checks such as no-disturbance simulation which produce flat lines; ring-down test, namely apply and remove a temporary fault without tripping any element should produce traces that initially oscillate but damp out acceptably

Generator related dynamic modeling data

If the actual system response is measured at or near a generating facility with more than one unit in service during the dynamic local event, the generator related dynamic modeling data should be closely reviewed. For instance, if the voltage response does not match, the excitation system, including power system stabilizer if equipped, should be reviewed. The Power System Stabilizer status for units nearby could play a key role in this effort.

FACT device dynamic modeling data

If the actual system response is measured at or near a FACTS device, the dynamic modeling data of the FACTS device should be reviewed.

Power flow model preparation

Bus voltage magnitude

Verify that the generation should be modeled as gross instead of net values

Verify capacitors and reactors are set correctly

Verify that all state estimator loads are accounted for

Ensure the state estimator’s extraneous loads are not modeled

Verify the polarity of all state estimator loads (e.g. some loads are actually sources due to PV generation)

Verify that the network configuration is modeled appropriately based on circuit breaker and switch status (e.g. does a bus need to be modeled as a split bus due to an open circuit?)

Verify that the modeled line and transformer impedances are consistent

Verify the no-load tap changers are modeled appropriately for all transformers

Verify that all planned and forced outages are modeled appropriately

Consider whether PI data should be used where state estimator data is questionable

Consider whether differences are due to measurement error

Verify HVDC systems are appropriately configured

Real power flow

Reactive power flow

Table A-1 Case preparation Guidelines

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Appendix B. Contacts for obtaining information and data

Information Required/ Questions

Concerned Department

Contact Person(s)

Contact Information

Planning Models

MISO Planning Modeling

Amanda Schiro, Manager; Joe Wax; Matthew Ladd;

TAMModeling@misoenergy.org;

ASchiro@misoenergy.org

JWax@misonenergy.org;

MLadd@misoenergy.org;

Outage Coordination Daily Base-case

CROW Mapping

MISO Outage Coordination

Jeanna Furnish, Manager Abiodun Olayiwola; Michael Catlin; Outage Coordination Inbox

OpsOutageCoordination@misoenergy.org;

jfurnish@misoenergy.org ;

mcatlin@misoenergy.org;

aolayiwola@misoenergy.org;

EMS State Estimator case (S.E.) EMS S.E. to IDC Mapping

MISO Model Engineering, Modeling & Market Engineering

Kyle Trotter, Manager Teneka Jackson

ktrotter@misoenergy.org ;

TJackson@misoenergy.org;

IDC Models MISO Seams Administration

Ron Arness, Manager; Prasad Shinde; Christine Ross;

TU_Seams2@misoenergy.org

rarness@misoenergy.org;

pshinde@misoenergy.org;

cross@misoenergy.org;

Synchrophasers Data (PMU)

MISO Engineering Technology Integration

Jay Dondeti, Manager; Ben Boutwell; Srivatsan Lakshminarasimhan

jdondeti@misoenergy.org ;

bboutwell@misoenergy.org ;

slakshminarasimhan@misoenergy.org ;

Dynamic Event MISO Real Time Operations

Raja Thappetaobula;

RThappetaobula@misoenergy.org ;

FNET System (Non MISO)

Prof Dr. Yilu Liu liu@utk.edu

Frequency Response Tool Score Cards

MISO Shift Operations, Standards Compliance & Strategy

Steve Swan Terry Bilke,

SSwan@misoenergy.org

Table B-1 MISO Contacts for obtaining information and data

For requirement R2, information can be requested from the following parties:

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MISO Member Transmission Operator Contact Information for MOD-033-1

Transmission Operator Name Name Email

ALLETE, Inc. (Minnesota Power, Inc.) Ruth Pallapati rpallapati@mnpower.com

Ameren Services Company Jason Genovese JGenovese@ameren.com

American Transmission Company, LLC

ATC EMS Support Steve Wendling

ATCEMS-IntModel@atcllc.com

sendling@atcllc.com

Ames Municipal Electric System Lyndon Cook lcook@city.ames.ia.us

Big Rivers Electric Corporation Chris Bradley chris.bradley@bigrivers.com

Board of Water, Electric, and Communications Trustees of the City of Muscatine, Iowa

Lewis Ross Omer Vejzovic

lross@mpw.org OVejzovic@mpw.org

City of Springfield, Illinois (Office of Public Utilities) Aaron Sullivan aaron.sullivan@cwlp.com

Cleco Power LLC Chris Thibodeaux christopher.thibodeaux@cleco.com

Columbia, Missouri, City of (Water & Light Dept.) Armin Karabegovic armin.karabegovic@como.gov

Consumers Energy Company

Michael Gaffney Brian Bushey

Michael.Gaffney@cmsenergy.com Brian.Bushey@cmsenergy.com

Cooperative Energy (formerly SMEPA) Jason Goar jgoar@CooperativeEnergy.com

Dairyland Power Cooperative Steve Porter Steve.Porter@DairylandPower.com

Duke Energy Indiana, LLC Phil Briggs Phil.Briggs@duke-energy.com

Entergy Entergy Transmission Operations Engineering TransmissionOperationsEngineering@entergy.com

Great River Energy Tim Mickelson tmickelson@grenergy.com

Hoosier Energy Rural Electric Cooperative, Inc. Todd Taft ttaft@HEPN.com

Indianapolis Power & Light Company Russ Mills russ.mills@aes.com

International Transmission Company (d/b/a ITC Transmission)

Ruth Kloecker Vinit Gupta (alternate)

rkloecker@Itctransco.com vgupta@itctransco.com (alternate)

ITC Midwest LLC Ruth Kloecker Vinit Gupta (alternate)

rkloecker@Itctransco.com vgupta@itctransco.com (alternate)

Lafayette Utility System

Stacee Dunbar Stewart Dover NercCompliance@lus.org

Michigan Electric Transmission

Ruth Kloecker Vinit Gupta (alternate)

rkloecker@Itctransco.com vgupta@itctransco.com (alternate)

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MISO Member Transmission Operator Contact Information for MOD-033-1

Transmission Operator Name Name Email

Company, LLC

MidAmerican Energy Company

Daniel Rathe Terry Harbour (alternate)

DARathe@midamerican.com TRHarbour@midamerican.com (alternate)

Minnkota Power Cooperative, Inc.

Will Lovelace Andy Berg

wlovelace@minnkota.com aberg@minnkota.com

Montana-Dakota Utilities, Co. Shawn Heilman Shawn.Heilman@mdu.com

Muscatine Power & Water Ryan Streck rstreck@mpw.org

Northern Indiana Public Service Company Lynn Schmidt lschmidt@nisource.com

Otter Tail Power Company Denise Keys Dkeys@otpco.com

Rochester Public Utilities Scott Nickels snickels@rpu.org

Southern Illinois Power Cooperative Jeff Jones jjones@sipower.org

Southern Indiana Gas & Electric Company (Vectren)

Ryan Abshier Mike Burk (alternate)

rabshier@vectren.com mburk@vectren.com

Southern Minnesota Municipal Power Agency Patrick Egan pjegan@smmpa.org

Wolverine Power Supply Cooperative Tyler Bruning tbruning@wpsci.com

Xcel Energy Jason Espeseth Jason.R.Espeseth@xcelenergy.com

Table B-2 MISO Member Contacts for obtaining information and data

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Appendix C. NERC Standard References

The following NERC standards provide a mechanism to request that equipment owners verify

models based on differences between simulations and real-time system performance. Refer to

the standards for complete details.

NERC Standard MOD-026-1

Under Applicability Section 4.2.4 this standard is applicable to any unit that meets NERC

registry criteria when technical justification is achieved by the Transmission Planner

demonstrating that the simulated unit or plant response does not match the measured unit or

plant response.

Requirement R2.1.1 includes the requisite for the Generator Owner to provide documentation

demonstrating the applicable unit’s model response matches the recorded response for a

voltage excursion from either a staged test or a measured system disturbance.

Requirement R3 states that 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 R6)

that the excitation control system or plant volt/var control function model is not usable,

Written comments from its Transmission Planner identifying technical concerns with the

verification documentation related to the excitation control system or plant volt/var

control function model, or Written comments and supporting evidence from its

Transmission Planner indicating that the simulated excitation control system or plant

volt/var control function model response did not match the recorded response to a

transmission system event.

The written response shall contain either the technical basis for maintaining the current model,

the model changes, or a plan to perform model verification (in accordance with Requirement

R2).

NERC Standard MOD-027-1

Per Section 4.2 this standard is applicable to units or multiple units over 100 MVA in Eastern

Interconnection. Requirement R2 allows Generator Owners to use a frequency excursion from

either a system disturbance or staged testing to verify models and parameters.

Requirement R3 states that 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,”

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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.

NERC Standard MOD-032-1 NERC MOD-032 provides a mechanism to go back to equipment owners to verify steady state

and dynamic data. Note that the Load Serving Entity (LSE) function was retired with FERC

approval. Any requirements listed in the NERC standards that refer to the LSE function are no

longer enforced. Dynamics reference item 5 refers to the LSE to provide data regarding

dynamic load. It may be necessary for Planning Coordinators to work with Transmission

Planners using reference item 10 to develop a requirement for provision of dynamic load data

by Transmission Owners or to use local procedures and Tariff references to obtain dynamic

load data.

R3. Upon receipt of written notification from its Planning Coordinator or Transmission Planner

regarding technical concerns with the data submitted under Requirement R2, including the

technical basis or reason for the technical concerns, each notified Balancing Authority,

Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, or

Transmission Service Provider shall respond to the notifying Planning Coordinator or

Transmission Planner as follows]

3.1. Provide either updated data or an explanation with a technical basis for maintaining the

current data;

3.2. Provide the response within 90 calendar days of receipt, unless a longer time period is

agreed upon by the notifying Planning Coordinator or Transmission Planner.

See MOD-032 Attachment 1 for further information. Presently there is a gap in MOD-032 with

retirement of the LSE NERC function for the recertification of dynamic load models.

NERC Standard IRO-010-2

4. Applicability

4.1. Reliability Coordinator.

4.2. Balancing Authority.

4.3. Generator Owner.

4.4. Generator Operator.

4.5. Load-Serving Entity.

4.6. Transmission Operator.

4.7. Transmission Owner.

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4.8. Distribution Provider.

R1. The Reliability Coordinator shall maintain a documented specification for the data

necessary for it to perform its Operational Planning Analyses, Real-time monitoring, and Real-

time Assessments. The data specification shall include but not be limited to:

1.1. A list of data and information needed by the Reliability Coordinator to support its

Operational Planning Analyses, Real-time monitoring, and Realtime Assessments

including non-BES data and external network data, as deemed necessary by the

Reliability Coordinator.

1.2. Provisions for notification of current Protection System and Special Protection

System status or degradation that impacts System reliability.

1.3. A periodicity for providing data.

1.4. The deadline by which the respondent is to provide the indicated data.

R3. Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator,

Load-Serving Entity, Transmission Operator, Transmission Owner, and Distribution Provider

receiving a data specification in Requirement R2 shall satisfy the obligations of the documented

specifications using:

…

3.2 A mutually agreeable process for resolving data conflicts

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Appendix D. Sample Request for Verification

Mr. or Ms. Equipment Owner

Via e-mail (or address information)

Dear Equipment Owner,

MISO as the NERC registered Planning Coordinator and Reliability Coordinator entity is

requesting that the model parameters for the <insert equipment owner or representative name

here and facility name here> for facility be verified under NERC standard <insert applicable

NERC standard MOD-026, MOD-027 (as a Transmission Planner), MOD-032 (for steady state)

or IRO-010 (as a Reliability Coordinator for Steady State)>.MISO has determined that the model

response of the <insert equipment owner or representative name here and facility name here>

as shown in Figure 1,<insert additional figure references if required> doesn’t meet the MISO

acceptable performance criteria per requirement R1.3 of MOD-033 standard. Model review and

tuning must be performed to meet the performance criteria. Please provide a response with a

change for the model, plan for changing or a technical basis for continued use of the existing

model within 90 calendar days. The response should be emailed to

TAMModeling@misoenergy.org

Figure D-1 Actual vs. Simulated Model Response

If I can provide any additional detail for this request, please contact me via e-mail at <insert e-

mail address> here or phone at <insert phone number here>.

Sincerely,

Engineer /s/

Title,MISO

Contact Details

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Appendix E. Reference Documents

“MOD-033 Methodology Reference Document”, NATF, Draft Jan, 2017

“Procedures for Validation of Powerflow and Dynamics Cases “, NERC

“Reliability Guideline: PMU Placement and Installation”, NERC Draft 9/22/2016

“System-Wide Model Validation 3002005746”, EPRI, 22-Oct-2015