MISO MOD-033-1 Model
Validation Process
Version 1.0
June 1, 2017
i
DOCUMENT REVISION HISTORY
Changes (additions, modifications, deletions) made to this document are recorded in the table
below.
Revision date
June 1, 2017
MISO
Version,
Section & Title
Version 1.0
Summary of
Changes
Initial version
Authors
Approver
Nihal Mohan,
Cody Doll
David Duebner
ii
Contents
1
2
a)
Purpose ............................................................................ Error! Bookmark not defined.
b)
Scope of validation ........................................................... Error! Bookmark not defined.
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
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
5
Applicable NERC Standards .......................................................................................14
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:
Start
Select a scenario
• Obtain real time
data (R2)
Prepare models,
run simulations
• Section 1 and 2
(R1.1,R1.2)
Evaluate model
performance
• Section 3(R1.3)
Address
differences
• Section 4(R1.4)
Stop
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.
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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.
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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: scale the loads in planning model to match the total system MW and Mvar in S.E.2
case for each Local Balancing Area (LBA). Loads denoted as non-scalable in the models
will not be scaled
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:3
Total in Planning Model = B+C MW/ Mvar4
A = C MW/Mvar4
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: Adjust the interchange data in the planning case to match the S.E.
real-time case.
3
4
Python script “MOD33MappingTool.py” developed by System Modeling for initial mapping may be used.
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. 5 Adjust Minnesota Power’s industrial large motor loads 6 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 issues7 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 3.8 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.
5
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.
6 Refer MOD-033 mapping workbook “MOD-033_EMS to IDC Equipment Mapping.xlsx” to perform
manual adjustments.
7 Attention should be paid to the list of issues are identified in 0, during application of guidelines.
8 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.
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 data9
2. OCDB planning case for event date from Outage Coordination group
Refer Appendix B for details on contact information.
9
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
Bus voltage magnitude
Acceptable Differences
±2% (>346 kV)
±3% (200>kV>345kV)
±4% (100>kV>199kV)
Generating Bus voltage magnitude ±2%
MVA Current flow
±10% or ±100 MVA
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,10 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
“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
10
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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
Figure 4-1 R1.4 process to resolve unacceptable differences
4.1 Applicable NERC Standards
Model or
equipment
Steady state
model
Applicable
NERC
Standard,
Document
MOD-032
IRO-010
Comment
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.
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Dynamic
Model
MOD-032
Table 4-1
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.11
Applicable NERC Standards resolving unacceptable differences
11
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 Realtime 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. The
contact information for referenced departments is mentioned in Appendix B.
Data
EMS S.E. case
PI Historian Data
EMS to Planning
Mapping
Frequency Response
Tool Score Card
Synchrophasor Data
Dynamic DR/ DFR
data13
Sequence of Event
Outage Information
Outage Coordination
Daily Base case
Required for
Steady State Validation
Steady State
Validation, Dynamic
Validation
Mapping the topology,
load, generation and
other quantities
Dynamic Model
Validation
Dynamic Model
Validation
Provided by
MISO EMS Modeling
MISO Real Time
Engineering Support
Format
PSSE .raw format
Importable in Microsoft
Excel
EMS Modeling MISO
Text, Microsoft Excel,
PDF
MISO Shift Operations
Microsoft Excel
MISO Real Time
Engineering Support,
TOP in MISO Regions
TOP in MISO Regions
Per unit, Positive
sequence data , Text,
CSV or Microsoft Excel12
Per unit, Positive
sequence data13
Log files, text, email.
Dynamic Model
Validation
Dynamic Model
MISO RC, TOP in MISO
Validation, Steady
Regions
State Validation
Steady State Validation
, Dynamic Model
MISO Outage
Validation
Coordination group
Steady State Validation
(CROW)
, Dynamic Model
Validation
Table 5-1 list of data required from RC and TOP
Outages Mapped to
PSSE models
PSSE .raw or .sav
format
End of procedure. Reference materials provided in Appendices.
12
If positive sequence data is not available, then MISO would require the process and information to
convert it in positive sequence
13 If available with TOP and RC
MISO
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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
check
Generator
related dynamic
modeling data
FACT device
dynamic
modeling data
Bus voltage
magnitude
Real power flow
Reactive power
flow
Dynamic model preparation
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
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.
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
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
Table A-1 Case preparation Guidelines
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Appendix B.
Contacts for obtaining information and data
Information
Required/
Questions
Planning
Models
Concerned
Department
Contact
Person(s)
Contact Information
MISO System
Modeling
David Duebner,
Manager;
Cody Doll;
David
Kapostasy;
[email protected];
Outage
Coordination
Daily Basecase
MISO Outage
Coordination
Scott Turner,
Manager
Abiodun
Olayiwola;
Michael Catlin;
Outage
Coordination
Inbox
[email protected];
[email protected] ;
[email protected];
[email protected] ;
EMS State
Estimator
case (S.E.)
EMS S.E. to
IDC Mapping
IDC Models
MISO Model
Engineering,
Modeling &
Market
Engineering
MISO Seams
Administration
Amanda Schiro,
Manager
Teneka Jackson
[email protected] ;
[email protected];
Ron Arness,
Manager;
Prasad Shinde;
Christine Ross;
[email protected]
[email protected];
[email protected];
[email protected];
Synchrophase
rs Data (PMU)
MISO
Operations
Tools &
Processes
Kristian Ruud,
Manager;
Kevin Frankeny;
Keith Mitchell;
Blake Buescher;
[email protected] ;
[email protected] ;
[email protected] ;
[email protected];
Dynamic
Event
MISO Real
Time
Operations
FNET System
(Non MISO)
MISO Shift
Operations,
Standards
Compliance &
Strategy
Raja
Thappetaobula;
[email protected] ;
Prof Dr. Yilu Liu
[email protected]
Steve Swan
Terry Bilke,
[email protected]
CROW
Mapping
Frequency
Response
Tool Score
Cards
[email protected]
[email protected];
[email protected] ;
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
[email protected]
Ameren Services
Company
Jason Genovese
[email protected]
American
[email protected]
Transmission
Curtis Roe
Company, LLC
Robert Krueger
[email protected]
Ames Municipal
Electric System
Lyndon Cook
[email protected]
Big Rivers Electric
Corporation
Chris Bradley
[email protected]
Board of Water,
Electric, and
Communications
Trustees of the City
Lewis Ross
[email protected]
of Muscatine, Iowa
Omer Vejzovic
[email protected]
City of Springfield,
Illinois (Office of
Public Utilities)
Aaron Sullivan
[email protected]
Cleco Power LLC
Chris Thibodeaux
[email protected]
Columbia, Missouri,
City of (Water & Light
Dept.)
Armin Karabegovic
[email protected]
Consumers Energy
Company
Robert Vermurlen
[email protected]
Cooperative Energy
(formerly SMEPA)
Jason Goar
[email protected]
Dairyland Power
Cooperative
Steve Porter
[email protected]
Duke Energy Indiana,
LLC
Phil Briggs
[email protected]
[email protected]
William Hamilton
Entergy
Melinda Montgomery
[email protected]
Great River Energy
Tim Mickelson
[email protected]
Hoosier Energy Rural
Electric Cooperative,
Inc.
Todd Taft
[email protected]
Indianapolis Power &
Light Company
Russ Mills
[email protected]
International
Transmission
Company (d/b/a ITC
Ruth Kloecker
[email protected]
Transmission)
Vinit Gupta (alternate)
[email protected] (alternate)
Ruth Kloecker
[email protected]
ITC Midwest LLC
Vinit Gupta (alternate)
[email protected] (alternate)
Lafayette Utility
Stacee Dunbar
System
Stewart Dover
[email protected]
Michigan Electric
Transmission
Ruth Kloecker
[email protected]
Company, LLC
Vinit Gupta (alternate)
[email protected] (alternate)
MISO
19
MISO Member Transmission Operator Contact Information for MOD-033-1
Transmission
Operator Name
Name
Email
MidAmerican Energy
Company
Daniel Rathe
[email protected]
Minnkota Power
Will Lovelace
[email protected]
Cooperative, Inc.
Andy Berg
[email protected]
Montana-Dakota
Utilities, Co.
Shawn Heilman
[email protected]
Muscatine Power &
Water
Ryan Streck
[email protected]
Northern Indiana
Public Service
Company
Lynn Schmidt
[email protected]
Otter Tail Power
Company
Denise Keys
[email protected]
Rochester Public
Utilities
Scott Nickels
[email protected]
Southern Illinois
Power Cooperative
Jeff Jones
[email protected]
Southern Indiana
Gas & Electric
Ryan Abshier
[email protected]
Company (Vectren)
Mike Burk (alternate)
[email protected]
Southern Minnesota
Municipal Power
Agency
Patrick Egan
[email protected]
Wolverine Power
Supply Cooperative
Tyler Bruning
[email protected]
Xcel Energy
Jason Espeseth
[email protected]
Table B-2 MISO Member Contacts for obtaining information and data
MISO
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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.

MISO
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,”
21


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.
MISO
22
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 Realtime 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
MISO
23
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
[email protected]
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 email address> here or phone at <insert phone number here>.
Sincerely,
Engineer /s/
Title,MISO
Contact Details
MISO
24
Appendix E.




MISO
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
25