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Frequency Response Initiative Generator Event Survey

Troy Blalock, NERC RS ChairmanPlanning Committee MeetingSeptember 13-14, 2016

RELIABILITY | ACCOUNTABILITY2

Agenda

• Why Primary Frequency Response is Important• Review the History and Industry Outreach• Discuss the Identified Issues Dead Band Outer Loop Controls

• Voluntary Initiative• Highlight Efforts Southern Company ,ISO-NE, Burns McDonnell• Frequency Response Guideline• Recommendation• Next Step: Generator Survey


• Essential for Reliability of the Interconnections Cornerstone for system stabilityo Line of defense to prevent Under Frequency Load Shedding(UFLS) o Prevent equipment damage

• Essential for System Restoration Droop response is critical in restoration efforts Hydro units and gas turbines are some of the first units to be restarted

• Compliance with NERC Standards BAL-003-1, BAL-001 Prevent future regulations related to generator frequency response

performance

• To accurately predict system events (Transmission Models)

Why Primary Frequency Response Is Important


NERC Outreach OEM and Engineering Firms


Generator Governor Frequency Response Advisory

• Advisory issued February 5th • Initiated by NERC Resource

Subcommittee Interconnections frequency

response has declined Eastern Interconnection Lazy L

profile 2010 and 2013 Generator Survey

Data

Generator Governor Frequency Response Advisory

http://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/2015%20Alerts/NERC%20Alert%20A-2015-02-05-01%20Generator%20Governor%20Frequency%20Response.pdf


Turbine OEM Reach Out to Customer Base


2012 Frequency Response Initiative Report

Page 37, Frequency Response Initiative Report, October 2012


Majority of generators in BA’s fleet/ East and West Interconnections are currently incapable of providing primary frequency responsive and we continue to commission new generation and the trend continues.

What is the Reliability Issue

1.System Restoration Plans are challenged

2.Transmissions Stability and other models assume generators are capable of response

3.BA’s get a significant portion of frequency from load and can not predict the load response or control it.

Problems


What has been learned- Deadbands exceed

Primary Frequency Response logic typically resides in the turbine controls.

Dead Bands Vary• Many exceed 36 mHz

or 2.16 RPMDroops Settings Vary• Majority Droops

reported 5%

Many Dead Bands Exceed 36 mHz

NERC Frequency Response Initiative Report - August 2012, Bob Cummings


Coordination with plant DCS is a requirement when operating in MW Set Point Coordinated Control.

What has been learned – Outer Loop Control


Illustration

450 MW

Frequency 60.000 Hz

150 MW

150 MW

150 MW

Graphic from GE info bulletin PSIB20150212

Mis

sing


Illustration

450 MW

Frequency 59.940 Hz

153 MW for little more than 1 second

150 MW

+/- Dead Band MW

153 MW for little more than 1 second


Mis

sing


Example

450 MW

Frequency 59.940 Hz

153 MW

150 MW

+/- Dead Band MW

153 MW

456 MW

6 MW



Example

400 MW

Frequency 60.000 Hz

150 MW

150 MW

100 MW

400 MW

0 MW


RELIABILITY | ACCOUNTABILITY15 Graphic from GE info bulletin PSIB20150212

Conventional Steam PlantFrequency 59.940 Hz

400 MW6 MW

406 MW

+/- Dead Band MW

406 MW


Tariff Misconception

• Tariff provisions vary but typically measure dispatch imbalance or deviation charges based on substantially longer time intervals (on the order of 30 to 60 minutes with a tolerance band of 5-10%)

• Tariff provisions typically allow for exemptions or recourse if a generating resource is subject to imbalance or deviation charges due to providing frequency response

Note: Contact your Transmission Provider for specific tariff information

Primary frequency response is a relatively small amount of energy for a short period Typically provided for about 120 seconds Roughly 0.5% of capacity


Voluntary Initiative


No Frequency Algorithm in DCS

Frequency Algorithm in Plant DCS

3 -175 MW GE7FA Gas Mark VIe Turbine

Improvements

3/3/2015


ISONE Generator Frequency Response after remediation (Sustained)Response)

1

Improvements

Alstom GT-24, 1x1, 340MVA

Provided by ISO-NE


Improvements


Improvements

Western Interconnection

Provided by Burns McDonnell

GE single shaft combined cycle 7001C/E


Eastern Profile Changing ? New Trend

03/22/16 11:32 EDT

1111 MW Trip

06/05/16 17:15 EST

918 MW Trip


Reliability Guideline: Primary Frequency Control

• Posted 12/15/2015


• According to BAL-003 2015 Data submittal, if R1 was in effect this past year:

• Western Interconnection 15 (5 of 15 FRO <-1 MW/.1Hz) of 38 BA’s not comply with R1.

• Eastern Interconnection 7 (5 of 7 FRO <-1 MW/.1Hz) of 35 BA’s would not comply with R1.

BAL-003-1.1


2015 BAL-003-1 Performance

Western Interconnection: BA performance 1.3 times greater than FRO.Meet IFRO 23 of 25 times

Eastern Interconnection: BA performance 2.3 times greater than FRO.Meet IFRO 30 of 30 times with room to spare


The Goal

Every BES Generator should have a working governor and be set in accordance with Frequency Response Guideline for system reliability and system restoration and provide primary frequency response between Pmin and Pmax.• Exemptions Nuclear, existing wind solar, or possibly some

others (environmental. etc.)

LGIA and SGIA should be modified to require the same for all future generation.


Next Step: Generator Survey

• Three Interconnections: Eastern, Western and Quebec conduct periodic generator surveys based on selected events over multiple years to measure generators individual performance. Generator owners would complete and provide survey data for all

synchronized BES generators exceptions: startup or shut down exempted. Surveys should be sent within timely manner of selected frequency

excursions. RS representatives in coordination with NERC shall select events with consideration of Point C or Nadir and/ or below recommended deadband with potential the maximum number of units on line between Pmin and Pmax. Recommended at least two event a years spaced out in such a way to allow generator to address any issues discovered.

Survey will be “voluntary” but should be followed up with NERC Section 800 data request for any survey responses not provided.


Additional Details

• All efforts should be made to make the data survey simplistic but meaningful. ERCOT has been called on to support. The survey should be able to inform GO how they performed.

• Generator information (name and ID ) should be coordinated to be mapped or associated to the various data bases (GADS, planning models etc.)

• NERC needs to provide site or method for GO’s to submit data.• Webinars should be established in advance of the survey to

advise GO’s of the survey requirements, potential issues with data storage in plant historians.

• Additional webinars with OEM and Engineering firms to provide resources to the industry.


Motion

• Recommend to the NERC PC, a motion to approve a generator data survey to be coordinated by Interconnection over multiple years to assess generator primary frequency response. Further this effort will involve outreach to the generators, with coordination with NAGF, to support the existing generation fleet to provide the capability of providing primary frequency response.


Troy Blalock, P.E.South Carolina Electric & Gas Company601 Old Taylor Rd.Cayce, SC 29033Mail Code J42, Cayce, SC 29033Office #: 803-217-2040Cell #: 803-206-8984Fax #: 803-933-8220Email: [email protected]

mailto:[email protected]

Phil Fedora, RAS ChairPlanning Committee MeetingSeptember 13-14, 2016

Reliability Assessment SubcommitteeStatus Update


Reliability Assessment SubcommitteePresentation

• Long Term Reliability Assessment• Probabilistic Assessment Improvement Task Force• 2016/2017 Winter Reliability Assessment


Long Term Reliability Assessment

Long Term Reliability Assessment• Major Milestones• Preliminary Key Findings• ProbA• ERS-M6• Timeline


SeptemberRAS reviews draft LTRAPC presentation of key findingsReview comments considered

OctoberProbA RAS presentationProbA narratives/dashboards developedProbA & ERS-M6 incorporated

NovemberPC, MRC & ERO-RAPA reviews LTRAReview comments consideredPC webinar/vote

DecemberLTRA sent to Board of TrusteesBoard of Trustees approval conference callLTRA release

Long Term Reliability AssessmentMajor LTRA Milestones

Summary of the major milestones for the completion for the 2016 Long-Term Reliability Assessment


Long-Term Reliability Assessment2016 Reliability Issues in Focus

#1: Reserve Margins in all assessment areas appear sufficient but continue to trend downward

2021 Peak Resource Reserve Margins (Year 5)

• No Assessment Areas fall below their Reference Margin Level in the short-term (5 years)



#1: An unconfirmed retirement scenario applied to the reserve margin analysis shows MISO falling under in 2018 and Texas RE-ERCOT falling under in 2021• Organization of MISO States’ 2016 Survey increases confidence of this

scenario in MISO.• Current state of Regional Haze ruling and CPP increases confidence of this

scenario in ERCOT.

MISO ERCOT



#2: Increasing reliability risks due to reliance on a single fuel type• 2015 Actuals (EIA) and 2016-2026 forecasted anticipated nameplate

capacity changes.



#3: Essentially Reliability Services should be included in long-term planning• Voltage, Frequency, and Ramping capability• CAISO experiences their projected duck curve 4 years earlier than

forecasted• Areas with largely increasing VER, asynchronous generation may develop

ramping challenges



#4: Uncertainty around the future of nuclear generation grows• Impacts to this uncertainty

High cost of operation/installations/commissions Aging units Environmental Regulation impacts State programs/initiatives


Long-Term Reliability Assessment2016 Schedule

Date Action ItemJanuary 22 Data and Narrative Request sent to Regional Executives and RASJune 10 Data due to NERCJune 24 Draft Narratives due to NERC and RAS, initiating the peer reviewsJune 29-30 RAS Conference Call: Assessment Area representatives present Methods & Assumptions (Part 2)July 01 Peer Reviewer comments due to RAS July 1-11 Respond to peer reviewer comments and modify narratives as neededJuly 11 Send updated narratives to RASJuly 12-13 RAS Meeting; SERC – Charlotte NC; LTRA Peer ReviewJuly 22 Corrections to Data and Final Narratives due to NERCJuly 22-September 2 Ongoing report development by NERC StaffAugust 23-24 ERO RAPA Meeting: review of Regional responses to narrative questionsSeptember 5-16 RAS Review of draft report (ProbA dashboards NOT included)September 13-14 PC Meeting; presentation of key findings, data overview, and request of PC member reviewers.September 19-23 NERC responds to RAS commentsOctober 4 ProbA Team presents to RAS October 14 ProbA dashboards/narratives due to NERCOctober 17-21 NERC incorporates ProbA dashboards and addresses ERS Measure 6 in the reportOctober 24-November 4 LTRA sent to PC, MRC, and ERO RAPA for reviewNovember 7-9 NERC responds to PC, MRC, and ERO-RAPA feedbackNovember 9 NERC sends updated report to PCNovember 10 PC webinar to review final reportNovember 9-16 PC electronic voting periodNovember 30 LTRA sent to NERC Board of TrusteesNovember 30-December 14 NERC Board of Trustees review periodDecember 14 Board of Trustees conference call to approve reportDecember 15 Target Release


• Start Date March 2016

• PAITF Enhancements Monthly Probabilistic Statistics: Base case and sensitivity case Data Forms Updated Methods and Assumptions table possible update Sensitivity Case: Probabilistic Statistics and Summary Table Assessment Areas’ Narratives

• ProbA deliverables Dashboards for the 2016 LTRA report ( By October, 2016) 2016 Full ProbA report (By March, 2017 release date)

Probabilistic AssessmentIntroduction


• Determination Process Inputs from the RAS, RAS-ProbA and ERO-RAPA

• Sensitivity case: Increase in Load Growth Percent increase by +2% in 2018 and +4% in 2020 for on peak demand Percent increase by +2% in 2018 and +2% in 2020 for MWh net energy

Probabilistic AssessmentSensitivity Case


Probabilistic AssessmentSchedule


• Two Part Approach Current and Historic Trend of CPS 1 Score – Resources Subcommittee Future Projections (three years out from present year) – ERS Ramping

Subgroup

ERS – Measure 6Introduction


Part 1 – Resources Subcommittee (RS) will review the CPS1 Scores on hourly basis


• Trend hourly CPS1 exceedances over a given threshold for Interconnections by BA’s Trend by Month Trend by Hours of the Day

• If there is a consecutive exceedance for more than three hours RS will evaluate results further and work with individual BA Trend of CPS1 hourly exceedance could be due to lack of non-dispatchable

units, off peak operational challenges, or other constraints (technology neutral)

• Evaluation done on Quarterly Basis

ERS Measure 6Review CPS1 Scores on Hourly Basis


Part 2 – ERS Ramping Subgroup Developing a Screening Tool to Determine Future Ramping Needs


• ERS Ramping Subgroup developed a screening methodology to determine the levels of penetration for non-dispatchableresources

• Methodology based on minimum net load of a system• This screening will determine the future ramping needs in

upcoming three years• Areas and BA’s will continue to evaluate the screening

ERS – Measure 6Screening for Future Ramping Needs


Reliability Assessment SubcommitteePAITF

Probabilistic Assessment Improvement Task Force• Technical Reference Document Approved• Recommendation to Disband the PAITF• Propose creation of the PAWG


Reliability Assessment SubcommitteeWinter Assessment

2016/17 Winter Reliability Assessment• Status• Schedule


Probabilistic Assessment Technical Guidelines DocumentJosh Collins – PAITF ChairPhil Fedora – RAS ChairNoha Abdel-Karim – NERC StaffPlanning Committee MeetingSeptember 13-14, 2016


ProbA Technical Guidelines DocumentIntroduction

• Probabilistic Assessment Improvement Task Force (PAITF) Under the Reliability Assessment

Subcommittee (RAS)

• Final Deliverable: ProbA Technical Guideline Document Identifies modeling guidelines and

other recommendations to support consistent development of NERC’s probabilistic assessments

PC Approval August 12, 2016

Comment Matrix (with Responses to PC Feedback)

http://www.nerc.com/comm/PC/_layouts/xlviewer.aspx?id=/comm/PC/PAITF/Report_Review_Comment_Matrix_ProbAGuidelines_July2016_Final.xlsx&Source=http://www.nerc.com/comm/PC/Pages/Probabilistic-Assessment-Improvement-Task-Force-(PAITF).aspx&DefaultItemOpen=1

http://www.nerc.com/comm/PC/PAITF/ProbA%20Technical%20Guideline%20Document%20-%20Final.pdf

http://www.nerc.com/comm/PC/PAITF/ProbA%20Technical%20Guideline%20Document%20-%20Final.pdf


ProbA Technical Guidelines DocumentExecutive Summary

Summary

NERC to develop and maintain documentation describing the establishment of Assessment Areas. 1

Regions and Assessment Areas to provide monthly reliability measures in their metrics calculations.2

Regions and Assessment Areas need to model seasonal load forecast uncertainty.3

Regions and Assessment Areas need to incorporateseasonal variations in their modeling of resource outages.4


ProbA Technical Guidelines DocumentExecutive Summary

Summary

Assessment Areas need to coordinate with neighboringareas and document coordination and modeling activities.5

Assessment Areas to perform the sensitivity modelingwithin the Core Probabilistic Assessment framework.6

Assessment Areas to address the reliability issues identified within the LTRA that impact resource adequacy, within the Special-Coordinated Probabilistic Assessment framework.

7


Probabilistic Metrics• Annual LOLH• Monthly LOLH • Annual EUE, both actual and normalized• Monthly EUE, both actual and normalized

Probabilistic Study Frequency and Study Years• With inputs from the RAS, RAS-ProbA, PAITF and ERO-RAPA Probabilistic assessment is on a biennial basis

• Assessment Areas study both year 2 and 4 of the Long-Term Reliability Assessment (LTRA).

• Year 2 reporting is to track and trend resource adequacy measures assessment to assessment.

ProbA Technical Guidelines DocumentCore Probabilistic Assessment


Load Modeling• 8,760 hourly annual load model• Load Forecast Uncertainty (LFU) Reasonable expectation of variability of the annual and seasonal peak load

forecasts• Documentation Impacts of Demand Side Management on load shapes and load forecasts Detailed narratives requested

Demand Side Management (DSM)• Known impacts of non-controllable demand response (DR) embedded in load

forecast• Model limitations of controllable1 DR explicitly or net impact based upon Historical Performance Contractual Obligation


1 Controllable DR is any DSM activities or programs that are directly controlled or dispatchedby the System Operator or Load-Serving Entity to influence the amount of electricity used.


Capacity Modeling• Thermal Generation Many factors discussed such as capacity ratings, forced outage rates, and

scheduled maintenance modeling.• Variable Energy Resources Approved modeling approaches include time series modeling and alternatively

seasonal accredited capacity contribution (i.e. Effective Load Carrying Capability)• Energy Limited Resources Provide flexibility in modeling and request thorough documentation on how

resources modeled probabilistically to recognize and reflect variability of primary source of water.

• Behind-the-meter Generation (BTMG)• Capacity Transfers (Imports and Exports)• Emergency Operating Procedures (EOP) Consider variability in the amount of relief obtainable and how it is prioritized



Transmission Modeling• Typically zonal (pipe and bubble) basis• Modeling technique dependent on modeling software capability• Flexibility is maintained to allow Assessment Areas to define their modeling

and resource deliverability requirements

Sensitivity and Scenario Modeling• Sensitivity Modeling: assess the impact of a change in an input parameter, all

else equal, on resource adequacy metrics.• Scenario Modeling: analysis performed to assess the impact of changes in

multiple inputs on resource adequacy metrics.• Assessment Areas only required to perform Sensitivity Modeling in the Core

ProbA due to minimal model rework and run time as compared to Scenario Modeling



Determination• Key findings from NERC’s LTRA and Core ProbA• NERC with input from RAS, PC and ERO-RAPA to develop risk framework to

identify need

Roles and Responsibilities• Coordination: NERC, Regions, and Assessment Areas• Data Collection: The Regions• Modeling: Case-by-Case basis determined through individual scope of work NERC has in-house probabilistic modeling capability.

• Review: NERC RAS

Modeling Requirements and Scope of Work• In general follow general methods and assumptions for Core ProbA May deviate based on scenario and scope of work

ProbA Technical Guidelines DocumentCoordinated NERC Regional Special Assessment


PAITF• Disbanded; Final Deliverable Approved

NERC RAS• Reestablish PAITF as the PAIWG to seek continual improvement to NERC’s

probabilistic assessments, foster coordination and collaboration, and discuss industry best practices.

NERC RAS ProbA Team• Incorporate monthly metric calculations into 2016 ProbA• Incorporate narrative questions from technical guidelines document into

2016 ProbA

ProbANext Steps


Performance AnalysisSubcommittee Update Paul Kure, Chair, NERC Performance Analysis Subcommittee Planning Committee Meeting September 13-14, 2016


• Chair Melinda Montgomery (Entergy) was chair for the past three years Paul Kure (RF staff) is new chair

• Vice Chair Heide Caswell (Pacificorp) was vice chair Maggie Peacock (WECC staff) is new vice chair

Leadership Change


• PAS activities Several SC conference calls and one meeting during the summer Several task team conference calls on Essential Reliability Services (ERS)

Measure 7 during the summero Two webinars with the System Analysis and Modeling Subcommittee (SAMS) on

data request instructions Beginning review of work plan and subgroup scope documents

Subcommittee Activities


• PAS task #2 (PC work plan) ERS Measure 7 (reactive - available and deployed) proof-of-concept data

collection Voluntary data request issued to Balancing Authorities Two follow-up webinars to discuss instructions FAQ document to be developed Data due October 6o Summer Peako Forecast data (three years) from Powerflow modelso Actual data (three years) from EMS/real time archives

SAMS to review data collected

Update Item 1


• PAS task #3 (PC work plan) Review of reliability metrics used in the State Of Reliability (SOR) report –

Results of review presented at December Planning Committee meeting

Update Item 2


• 2017 SOR schedule SOR to be completed and approved prior to FERC Technical

conference in June Year end data not available until first quarter Desire for additional review time by PC/OCo Expanded chapter review (2017)o Operating year data (2018?)

Proposal to increase review time will be presented at December PC meeting

Request at the December PC meeting for reviewers of SOR report

Update Item 3


• December PC meeting Review of metrics to be included in 2017 SOR Proposal to increase available time for PC/OC SOR report review Update on ERS measure 7 data collection proof-of- concept Update on PAS work plan and scope documents for GADS, TADS, DADS Request for PC reviewers of SOR and individual chapters

Next Steps


Generator Availability Data SystemWind Data Reporting Instructions Changes

Donna Pratt, Sr. Advisor, Performance AnalysisPlanning Committee MeetingSeptember 13, 2016


• Requesting Planning Committee approval of the minor revisions to the Wind Data Reporting Instructions (DRI) Generating Availability Data System Working Group (GADSWG) made

minor revisions to the wind DRI document based on platform being used DRI provides guidance for mandatory GADS reporting of wind generatorso Modifies the existing Section 1600 mandatory data collection for GADS

• Section 1600 Data Request for wind data reporting, which included the DRI, was approved by NERC’s Board of Trustees on November 5, 2015

Purpose


• GADSWG: August 16,2016 Detailed walk-through of the changes No objections raised Stakeholders are eager to receive updated versions of the Wind DRI as

soon as possible to modify wind plant owner reporting systems to prepare for data reporting

• PAS: August 23, 2016 Review of the changes using the revision history in the DRI Discussed GADSWG review and feedback Questions were raised about the difference in the platforms and the

schedule for implementation No objections raised

PC Sub-Group Reviews


• Minor changes have been made to the GADS Wind DRI to reflect the implementation on the new platform Fundamental concepts preserved

• Updated file formats Additional reporting options Consolidation of data elements Data fields reorganized

• Consistent use of terms and definitions throughout the document

• Sorting of tables and lists for easier reference• Added process for managing ownership of wind units within the

new system

Summary of Changes


• Stakeholders understand and support the proposed minor changes to the Wind DRI Allows the industry to standardize on concepts and terminologyo Fundamental concepts preserved

Provides additional clarity on data elements and reporting procedures that are specific to implementationo Improves data quality

Conclusions


Eastern Interconnection Reliability Assessment Group

ERAG

Multi-regional Modeling Working GroupModeling Improvements

Presented by,John Idzior ReliabilityFirst CorporationMMWG Chair

NERC Planning Committee MeetingPhoenix, AZ

September 13, 2016


ERAGWhat is ERAG?• Agreement signed by 6 EI Regions Perform Studies Assemble power flow and dynamic cases

• Management Committee (Regional Staff) Steering CommitteeStakeholder RepresentativesPerform Studies

MMWG - Model BuildingPlanning Coordinators (voting members)NERC & Regional staff observers (non-voting members)

9/6/2016 2


ERAGModel Building Process• Annual Set of Cases Developed Power Flow - 12 Cases Dynamics - 8 Cases

• Data Collected under MOD-032• Collected and submitted by PC representatives• Cases assembled and tested by contractor

9/6/2016 3


ERAG2016 Series ModelsYear Season Dynamic

2017 Spring light Load X

2017 Summer Peak

2017/18 Winter Peak X

2018 Spring Light Load X

2018 Summer Peak


2021 Summer Shoulder

2021 Spring Light Load X

2021 Summer Peak


2026 Summer Peak X


9/6/2016 4


ERAGDevelopment Cycle

Transmission Owners

Planning Coordinator

MMWG Contractor

MMWG Members, Regions, NERC, Single Point of Contact for Industry Users

Industry Users

9/6/2016 5


ERAGData Checks• Unrealistic PMAX and PMIN• Unrealistic QMAX and QMIN• PGEN outside range• Reactive device regulating node voltage more than one bus away.• Switch shunts with VHI - VLOW < 0.0005• Controlled Bus Checks (CNTB) - Errors • Transformers with voltage band < 1.95 * step• RAW read warnings produced by PSSE.• Buses with duplicate bus names within the same control area. Duplicate bus names are defined as having the same twelve character name and six

character voltage fields.• Buses with blank voltage fields.• Machines connected to a Code 1 bus.• Code 2 buses with no machines modeled.• Machines with zero or non-positive RMPCT.• Machines with GENTAP > 1.1 or < 0.9.• Branches with Rate B < Rate A (Required) or Rate A = 0.0 and Rate B = 0.0 (Warning) for 100 kV and above. • Three winding transformers with Rate B < Rate A (Required) or Rate A = 0.0 and Rate B = 0.0 (Warning).• Transformers with RMAX <= RMIN or VMAX <= VMIN. Required for non-fixed tap transformers only.• Transformers with RMAX = 1.5 and RMIN = 0.51. Required for non-fixed tap transformers only.• Transformers with VMAX = 1.5 and RMIN = 0.51. Required for non-fixed tap transformers only.• Transformers with RMAX, RMIN, VMAX or VMIN = 0. Required for non-fixed tap transformers only.• Switched shunts with missing Block 1 steps.• Branches with loading above 100% of Rate A or B for 100 kV and above.• Bus voltages under 90% or above 110% for 100 kV and above.• Branches with resistance > |reactance| for 100 kV and above. • Buses with owner numbers out of range.• Buses with zone numbers out of range.• Buses with numbers out of range.

9/6/2016 6


ERAGCase Quality Enhancements• Corrected ‘drift’ in exceptions to data checks• Enforced the removal of black box models Generic Wind Models Eliminated many industry found issues User Models Must be Documented

• Voltage schedule conflicts: Include off-line devices • Tap Step Violations: No Exceptions (All voltage levels)• Low Emergency Rating: No Exceptions (All voltage levels)• High Emergency Rating (>= 3X Rate A): Not allowed for

69kV+, Documented Exceptions Allowed• Thermal Overloads: Not allowed for 69kV+ and all GSUs

9/6/2016 7


ERAGCase Quality Enhancements• Unreasonable Inertia Constants - constants

should be within reasonable ranges 1.5 <= H <= 9.0

• Severe Saturation Factor Errors S(1.0) and S(1.2) should be between 0 & 1 S(1.0) should be <= to S(1.2)

• Generator speed damping coefficient should =0 for non-classical machine models

• Turbine-Governor Power Development Fractions should add to 1.0 (K1…N, Ks)

9/6/2016 8


ERAGCase Quality Enhancements• Adopted use of NERC Libraries of Standardized

Powerflow and Dynamic Models• Feedback loop for data errors discovered Eliminated recurring issues Industry notification to current known users

• Process to ensure timely publishing of cases• Case list alignment with TPL standards

9/6/2016 9


ERAGFuture Enhancements• NERC Case Quality Metrics MMWG case scores Committed to constantly improve quality

• Future versions of PSS®E Baseload flag: generator data record that

determines response of governor control limits during transient stability simulation Governor deadband modeling due to governor

model changes

9/6/2016 10


ERAG

John IdziorSenior Engineer, ReliabilityReliabilityFirst Corporation

[email protected]

9/6/2016 11

Modeling Improvements Initiative Update

Ryan D. Quint, NERCNERC Planning Committee MeetingSeptember 13-14 2016


Case Quality Metrics AssessmentPhases 1 and 2

Informational Update


• Case Quality: Reasonableness of the data for individual Element models that comprise the powerflow and dynamics cases. Powerflow Metrics: assessment of quality of powerflow base case as

developed by interconnection-wide case creation entities Dynamics Metrics: assessment of quality of associated dynamics case –

component models

• Assessments Phase 1 (2015): Initial development of criteria and testing; main focus on

powerflow case Phase 2 (2016): Re-assessment of Phase 1 metrics; additional metrics, focus

on dynamics Phase 3 (2017): At a minimum, assessment of Phase 1 and 2 metrics on new

cases (trending); possible new metrics

Case Quality Metrics Assessment


Powerflow and Dynamics MetricsPhases 1 and 2

Phase Powerflow Dynamics

Phase 1(2015)

• Pmax and Pmin violations• Scheduled interchange equality• Vsched conflicts• Transformer tap steps• Thermal rating consistency• Line and transformer loading

• Generator netting• Generator classical model

representation• Consistence reactance values

Phase 2(2016)

• Generator reactive dispatch at limits• Generator reactive limit power

factor• Positive sequence circulating current• Load power factors• Generator impedances

• Generator inertia and time constants • Saturation factors and “severe” factors• Generator speed damping coefficient • Turbine-governor time constants• Turbine power development fractions• GAST models• DC exciter self-excitation parameters• WT3E electrical wind speeds


EI Powerflow Results

Steady-State MetricsCase 2016SUM 2016WIN 2016SLLPhase Metric Perf Score

(%) Perf Score (%) Perf Score

(%)

Phase I

Pmax Violations 6 / 6100 0.10 18 / 5255 0.34 1 / 3621 0.03Pmin Violations 1 / 6100 0.02 2 / 5255 0.04 3 / 3621 0.08Scheduled Interchange Sum 0.001 -0.001 0.000Voltage Schedule Conflicts 25 36 35Tap Step Violations 8 / 19151 0.04 8 / 19232 0.04 18 / 19072 0.09Tap Step Violations (Severe) 3 / 19151 0.02 3 / 19232 0.02 3 / 19072 0.02Low Emergency Rating 11 / 85596 0.01 21 / 85816 0.02 13 / 85347 0.02High Emergency Rating 89 / 85596 0.10 93 / 85816 0.11 90 / 85347 0.11

Thermal Overloads 148 / 85596 0.17 129 / 85816 0.15 67 / 85347 0.08

Thermal Overloads (Severe) 96 / 85596 0.11 99 / 85816 0.12 46 / 85347 0.05

Phase II

Gen Reactive at Limits 1155 / 4679 24.68 875 / 3880 22.55 837 / 2481 33.74

Gen Reactive Limit Power Factor 679 / 5094 13.33 1099 / 4304 25.53 401 / 2822 14.21

Pos Seq TX Circulating Current 0 / 2669 0.00 0 / 2681 0.00 0 / 2652 0.00

Poor Load Power Factor 116 / 42448 0.27 100 / 42365 0.24 165 / 40933 0.40

Generator Rsource:Xsource Ratio 0 / 6100 0.00 0 / 5255 0.00 0 / 3621 0.00


TI Powerflow Results

Steady-State MetricsCase NT2017 Summer NT2018 LL FY2021 SummerPhase Metric Perf Score


(%)

Phase I

Pmax Violations 160 / 653 24.50 14 / 422 3.32 112 / 649 17.26Pmin Violations 17 / 653 2.60 71 / 422 16.83 15 / 649 2.31Scheduled Interchange Sum 0.0 0.0 0.0Voltage Schedule Conflicts 4 6 1Tap Step Violations 45 / 1148 3.92 41 / 1170 3.50 45 / 1156 3.89Tap Step Violations (Severe) 2 / 1148 0.17 0 / 1170 0.00 2 / 1156 0.17Low Emergency Rating 1 / 7963 0.01 1 / 8028 0.01 0 / 8020 0.00High Emergency Rating 6 / 7963 0.08 6 / 8028 0.08 10 / 8020 0.13Thermal Overloads 13 / 7963 0.16 22 / 8028 0.27 18 / 8020 0.22Thermal Overloads (Severe) 11 / 7963 0.14 17 / 8028 0.21 13 / 8020 0.16

Phase II

Gen Reactive at Limits 120 / 604 23.44 112 / 372 30.11 130 / 600 21.67Gen Reactive Limit Power Factor 68 / 644 10.56 49 / 412 11.89 63 / 640 9.84

Pos Seq TX Circulating Current 0 / 59 0.00 0 / 60 0.00 0 / 60 0.00Poor Load Power Factor 906 / 4047 22.39 741 / 4349 17.04 874 / 4419 19.78Generator Rsource:Xsource Ratio 0 / 653 0.00 0 / 422 0.00 0 / 649 0.00


WI Powerflow Results

Steady-State MetricsCase 16HS3a 16hw3a1 2016SLLPhase Metric Perf Score


(%)

Phase I

Pmax Violations 11 / 3033 0.36 12 / 2560 0.47 5 / 2281 0.22Pmin Violations 11 / 3033 0.36 16 / 2560 0.63 11 / 2281 0.48Scheduled Interchange Sum 0.0 0.0 0.0Voltage Schedule Conflicts 159 / 8401 1.89 142 / 8012 1.77 244 / 8401 2.90Tap Step Violations 379 / 8401 4.51 153 / 8012 1.91 379 / 8401 4.51Tap Step Violations (Severe) 11 / 8401 0.13 10 / 8012 0.12 11 / 8401 0.13Low Emergency Rating 37 / 25170 0.15 44 / 24632 0.18 35 / 25165 0.14High Emergency Rating 5 / 25170 0.02 5 / 24632 0.02 3 / 25165 0.01Thermal Overloads 8 / 26008 0.03 30 / 25401 0.12 1 / 26005 0.00Thermal Overloads (Severe) 3 / 26008 0.01 17 / 25401 0.07 0 / 26005 0.00

Phase II

Gen Reactive at Limits 532 / 2255 23.59 468 / 1927 24.28 430 / 1654 25.99Gen Reactive Limit Power Factor 449 / 3259 13.77 454 / 3186 14.25 448 / 3258 13.75

Pos Seq TX Circulating Current 0 / 1812 0.00 0 / 1836 0.00 0 / 1814 0.00Poor Load Power Factor 9 / 7205 0.12 13 / 6844 0.19 8 / 5339 0.15Generator Rsource:Xsource Ratio 4 / 4063 0.10 5 / 3985 0.12 4 / 4063 0.10


EI Dynamics Results

Dynamics MetricsCase 2016SUM 2016WIN 2016SLLPhase Metric Perf Score (%) Perf Score (%) Perf Score (%)

Phase I

Gens without Models 61 / 6285 0.97 72 / 6285 1.15 59 / 6280 0.94Netted Gens with Models 21 / 4619 0.46 22 / 3927 0.56 18 / 2523 0.71Netted Generators 56 / 4619 1.21 62 / 3927 1.58 46 / 2523 1.82Gens with Classical Models 18 / 4632 0.39 18 / 4724 0.38 18 / 4652 0.39Inconsistent Reactance's 20 / 5327 0.38 20 / 5309 0.38 19 / 5326 0.36

Phase II

Inconsistent Time Constants 2 / 5409 0.04 2 / 5392 0.04 2 / 5408 0.04Unreasonable Inertia Constants 735 / 6790 10.83 736 / 6763 10.88 719 / 6774 10.61Unreasonable Saturation Factors

2404 / 5409 44.44 2388 /

5392 44.29 2403 / 5408 44.43

Severe Saturation Factors 61 / 5409 1.13 63 / 5392 1.17 61 / 5408 1.13PSS but no Excitation 14 / 6285 0.22 14 / 6285 0.22 14 / 6280 0.22Inconsistent Speed Damping 402 / 6276 6.41 402 / 6249 6.43 390 / 6259 6.23Inconsistent Lead-Lag Time Const 38 / 1919 1.98 38 / 1929 1.97 38 / 1907 1.99

Erroneous Power Dev Fractions 361 / 622 58.04 361 / 623 57.95 360 / 620 58.07

GAST Models 1032 / 5157 20.01 988 / 5128 19.27 1029 /

5112 20.13

DC Exciter Self-Excitation Errors 150 / 1318 11.38 150 / 1319 11.37 150 / 1323 11.34Inconsistent Type III Wind Speeds 1 / 377 0.27 1 / 379 0.26 1 / 377 0.27


TI Dynamics Results

Dynamics MetricsCase NT2017 Summer NT2018 LL FY2021 SummerPhase Metric Perf Score (%) Perf Score (%) Perf Score (%)

Phase I


Phase II

Inconsistent Time Constants 0 / 472 0.00 0 / 485 0.00 0 / 472 0.00Unreasonable Inertia Constants 69 / 524 13.17 81 / 537 15.08 69 / 524 13.17Unreasonable Saturation Factors 203 / 472 43.01 205 / 485 42.27 202 / 472 42.80

Severe Saturation Factors 10 / 472 2.12 10 / 485 2.06 10 / 472 2.12PSS but no Excitation 1 / 645 0.16 1 / 677 0.15 1 / 651 0.15Inconsistent Speed Damping 47 / 520 9.04 59 / 533 11.07 47 / 520 9.04Inconsistent Lead-Lag Time Const 0 / 130 0.00 0 / 147 0.00 0 / 125 0.00

Erroneous Power Dev Fractions 6 / 25 24.00 8 / 25 32.00 6 / 24 25.00GAST Models 37 / 568 6.51 37 / 582 6.36 37 / 729 5.08DC Exciter Self-Excitation Errors 8 / 74 10.81 8 / 74 10.81 9 / 74 12.16Inconsistent Type III Wind Speeds 0 / 0 N/A 0 / 0 N/A 0 / 0 N/A


WI Dynamics Results

Dynamics MetricsCase 2016SUM 2016WIN 2016SLLPhase Metric Perf Score (%) Perf Score (%) Perf Score (%)

Phase I


Phase II

Inconsistent Time Constants 213 /3351 6.36 217 / 3359 6.46 213 / 3342 6.37Unreasonable Inertia Constants 622 / 3354 18.55 622 / 3362 18.50 619 / 3345 18.51Unreasonable Saturation Factors 1869 / 3351 55.77 1884 / 3359 56.09 1859 / 3342 55.63Severe Saturation Factors 243 / 3351 7.25 255 / 3359 7.59 243 / 3342 7.27PSS but no Excitation 18 / 1726 1.04 22 / 1711 1.29 12 / 1718 0.70Inconsistent Speed Damping 313 / 3351 9.34 340 / 3359 10.12 312 / 3342 9.34Inconsistent Lead-Lag Time Const 24 / 1444 1.66 34 / 1454 2.34 24 / 1430 1.68Erroneous Power Dev Fractions 21 / 224 9.38 21 / 238 8.82 21 / 224 9.38GAST Models 30 / 2337 1.28 31 / 2319 1.34 30 / 2322 1.29DC Exciter Self-Excitation Errors 52 / 665 7.82 52 / 696 7.47 52 / 662 7.85Inconsistent Type III Wind Speeds 1 / 102 0.98 1 / 77 1.30 1 / 103 0.97


• Pmax and Pmin Violations ERCOT (timing of case release)

• Generator Reactive Limits All interconnections, units at Qlim

• Generator Reactive Limits Power Factor Unreasonable Qmax or Qmin based on Pmax

• Generator Time Constants• Generator Inertia Constants Units with very small inertia constant

• Saturation Factors Many units with saturation factors outside reasonable (and severe) ranges.

Phase 2 Metrics AssessmentObservations


• Speed Damping D Non-classical gen models with non-zero damping value

• Turbine-Governor Power Development Fractions Units with governor model with fractions that do not add to 100%

• GAST Model NERC developing Modeling Notification for GAST; predominant in EI.

• Self-Excitation Parameter for DC Exciters Many units with small positive rather than small negative value.

Phase 2 Metrics AssessmentObservations


Phase 1 Metrics Comparison

Western

Texas

Eastern

• No major upward trends in Phase 1 metrics (majority < 5% level)

• ERCOT models continue to have severe violation of Pmax and Pmin Phase 1 assessment posted after new cases

created. Will be addressed in next year’s case creation.


Appendix MaterialsIndustry Supporting based on Findings

• Open-circuit magnetization curve: Voc to Ifd,nl relationship

• Air-gap line: Ifd required to overcome reluctance of air-gap

• Deviation at higher Ifd due to saturation of iron in rotor and stator of machine

• Tool developed by the USACE for fitting open circuit and V-curve test data for GENTPJ model Posted to NERC SAMS page (HERE)

with instruction manual (HERE).

0 0.5 1 1.5 2 2.5 3

Lad

Ifd

0

0.2

0.4

0.6

0.8

1

1.2

1.4

Exponential Characteristic

Quadratic Characteristic

Unsaturated Characteristic

http://www.nerc.com/comm/PC/System%20Analysis%20and%20Modeling%20Subcommittee%20SAMS%20201/Copy%20of%20GENTPJ%20Steady%20State%20Parameter%20Estimation%202016-06-08%20Locked.xlsm

http://www.nerc.com/comm/PC/System%20Analysis%20and%20Modeling%20Subcommittee%20SAMS%20201/Generator%20Steady%20State%20Parameters%20Estimation%20Tool%20-%20FINAL_v2.pdf


• Goal: feedback loop between case creation & case quality metrics Open discussion on metrics and how/which to adopt

• Conference calls/presentations between NERC Staff and MOD-032 designees to share observations and results

• MMWG collaboration with NERC adopting applicable data quality checks

• ERCOT applying Phase 1 and 2 data quality checks during case creation. Phase 1 metrics adopted for this year’s cases.

Feedback Loop with MOD-032 Designees


Other Modeling Efforts

Informational Update


Case Creation Contingency Testing

• Adding requirements to study largest “credible” or studied contingency for each interconnection Based on, at a minimum, BAL-003-1 Resource Loss Protection Criteria Help ensure numerical robustness

• Updates ERCOT cases currently not tested against largest contingency, but ERCOT

will start including this test MMWG adopting Rockport event as worst contingency tested WECC tests 2 Palo Verde outage in case creation process


Plant-Level Controls and Protection Modeling Task Force (PCPMTF)

• Studying effects of plant-level, turbine, and boiler control and protection systems

• Outlining impacts plant control and protection systems have on unit reliability and system stability during grid disturbances

• Task Force Recommendations Adoption of models similar to gp1 (and gp2) (GE PSLF) – monitor, provide

warnings of potential unit tripping due to encroachment on trip-zones Adopt use of models that are more detailed and able to represent the

boiler dynamics and coordinated control such as TGOV5 and ccbt1 Inclusion of Volt/Hz, over excitation limiter, under excitation limiter and

reverse power dynamic models in future year planning cases.

• Milestones – Technical report to be presented in Q4 2016


Dynamic Load Modeling (LMTF)

• Industry forum for dynamic load modeling practices • Software implementation robustness by user input, benchmark

testing, and support• Coordinated development of new models and improvement to

existing models• Discussing and developing modeling guidance materials and

guidelines Modeling Guidance for DER in Dynamic Load Modeling Load Composition Guideline (expected Q1 2017)


Renewable Energy Modeling

• Growing penetration of renewable energy resources across North America

• Results in growing importance for accurate and robust modeling of these resources for planning and operating the grid reliably

• Clear outcome or next step of ERSWG and DERTF to deep dive focus on renewable models Share current modeling practices for renewables Educate system planners on renewables models available Ensure uniform robust implementations Tackle new or updated renewables modeling techniques for industry Understand impacts and concerns with renewables in weak grids


Addressing Ongoing Modeling Issues

• Initialization errors Renewable energy resources netted due to modeling issues –

unacceptable “workaround” to modeling problems HVDC modeling problems including .dll version problems causes inability to

successfully initialize case for study Software initialization problems and crashing – not enough context

provided for planners to address problems (e.g., dynamic load models)

• Numerical instability for large, credible contingencies


SAMS and MWGUpdate

Michael R. LombardiChair, System Analysis and Modeling SubcommitteePlanning Committee MeetingSeptember, 2016


SAMS Leadership Transition Completed

SAMS Leadership transitioned in June 2016• Michael R. Lombardi, Chairman

Northeast Power Coordinating Council, Inc.New York, New York [email protected]

• Hari Singh, Vice ChairmanXcel Energy, Inc.Denver, Colorado [email protected]

• Ryan Quint, NERC Staff [email protected]





SAMS Update September PC Meeting

• Review of SAMS current efforts focusing on: SAMS Restructuring (SAMS Informational Item) FERC Order 786 Directives (SAMS Informational Item) Reliability Guideline on Reactive Power Planning (SAMS Informational

Item) Modeling Notifications (MWG Informational Item) Modeling Guidance: DER in Dynamic Load Models (SAMS/LMTF seeking PC

Reviewers) Dynamic Load Modeling Technical Reference Document (separate PC

agenda item)


SAMS Restructuring Concept

SAMS• Transmission Planning topics• Policies• FERC Directives• Advisory role to system analysis efforts

MWG• Powerflow modeling• Dynamics modeling• Modeling Notifications

LMTF• Dynamic load modeling• Guidance for future

models• Industry expertise

PCPMTF• Plant-level controls

expertise• Modeling improvements

• All groups meet independently• Chair or coordinator reports up to SAMS at each meeting

SAMS Current Structure



SAMS

Load Modeling Task Force

(LMTF)

Plant-Level Controls and

Modeling Task Force

(PCPMTF)

• Groups meet concurrently – combine to SAMS meeting All groups meet same location 3-4x per year.

• Chair or coordinator lead meetings, report up at SAMS meeting

SYSTEM ANALYSIS• Transmission Planning topics• Policies• FERC Directives• Advisory role to system analysis efforts

MODELING• Powerflow modeling• Dynamics modeling• Modeling Notifications

Power Plant Modeling and

Validation Task Force

(PPMVTF)

Renewable Energy

Modeling and Validation Task

Force(REMVTF)

…

SAMS Proposed Structure



*Beginning Q1 or Q2 2017

MONDAY TUESDAY WEDNESDAY THURSDAY FRIDAY

AM

TRAVEL

PCPMTF

PPMVTF

LMTF

REMVTF

SAMS

Task Team Report Outs

TRAVELPM LMTF

REMVTF

SAMS

Modeling

SAMS

System Analysis

Meeting Agenda Example


FERC Order 786 Directives

• FERC issued Order No. 786 on October 17, 2013 Final Rule Approving Reliability Standard TPL-001-4, Transmission System

Planning Performance Requirements Included two directives: Paragraph 40 and Paragraph 89

• Paragraph 40 – “… modify Reliability Standard TPL-001-4 to address the concern that the six month threshold could exclude planned maintenance outages of significant facilities from future planning assessments.”

• Paragraph 89 – “… directs NERC to consider a similar spare equipment strategy for stability analysis upon the next review cycle of Reliability Standard TPL-001-4.”


SAMS Assessment – ¶40 – Planned Maintenance Outages

• NERC Project 2015-10, Single Points of Failure TPL-001 Standard Drafting Team nomination period closed 8/5/16

• Timing Considerations: Order 786 Directive issued October 17, 2013 Order 818 issued November 19, 2015o NERC Reliability Standard IRO-017-1, Outage Coordinationo Enforcement Date April 1, 2017

• SAM Recommendations (Input to NERC Project 2015-10) Modifying IRO-017-1 and TPL-001-4 IRO-017 should assure that all types of known scheduled outages are

being reviewed and coordinated to mitigate reliability impact, as the most cost-effective means to address the intent of the NERC directive


SAMS Assessment – ¶40 – Planned Maintenance Outages

• SAM Recommendations (continued) Add to IRO-017-1, R1:o Describe how the review of known scheduled outages by the RC, PC, TO, and TP

will be integrated into transmission plan development.o Describe whether, how, and which known scheduled outages should be included

in the Near Term Assessment of the Planning Horizon required by TPL-001-4.o Describe how emerging challenges and the inability to schedule outages will be

communicated from the TO and RC to the TP and PC to be addressed in a future Corrective Action Plan pursuant to TPL-001-4.

TPL-001-4 Requirement 1.1.2 should be modified:o Removing “with a duration of at least six months”o Adding language referencing the outage coordination process developed in IRO-

017-1 Requirement R1 as described above


SAMS Assessment – ¶89 – Stability Analysis for Long Lead Time Outages

• NERC Project 2015-10, Single Points of Failure TPL-001 Standard Drafting Team nomination period closed 8/5/16

• TPL-001-4, R2.4 [Near-Term Transmission Planning Horizon portion of the Stability analysis] requires the following studies: System peak load for one of the five years [R2.4.1] System off-peak load for one of the five years [R2.4.2] Sensitivity cases [R2.4.3]

• SAM Recommendations (Input to NERC Project 2015-10) Include new sub-requirement R2.4.4 that requires Stability analysis for

contingencies P1 and P2 for long lead time equipment that does not have a spare equipment strategy in place to return that Element to service within one year (such as transformers).


SAMS Assessment – ¶89 – Stability Analysis for Long Lead Time Outages

• SAM Recommendations (continued) Proposed TPL-001-4 sub-requirement language states:“2.4.4. When an

entity’s spare equipment strategy could result in the unavailability of major Transmission equipment that has a lead time of one year or more (such as a transformer), the impact of this possible unavailability on System performance shall be studied. The studies shall be performed for the P1 and P2 categories identified in Table 1 with the conditions that the System is expected to experience during the possible unavailability of the long lead time equipment.”


Reliability Guideline on Reactive Power Planning

• Informational update and plan for approval Industry comment period recently completed 140+ industry comments received SAMS sub-group will develop response to industry comments and draft an

updated guideline SAMS on track to seek final approval of guideline at December PC meeting


Modeling Notifications

• Notification Process Improvement ERO-RAPA recommended the roll out of model notifications to the industry

be improved To improve both the dissemination and the understanding of the basis for

a model notification, an industry webinar will be conducted when each new model notification is released


Modeling Notifications

• “Conversion to GENTPJ Generator Model” Providing update on notification for industry awareness, no approval

required by PC as per Modeling Notification Process Document Recommends converting the GENSAL (salient pole) and GENROU (round

rotor) generator models to the GENTPJ generator model Predominant difference between the GENROU/GENSAL and GENTPJ

models is how they account for saturation Topic vetted with subject matter experts, already adopted in WECC Industry webinar with SMEs to be setup soon


Modeling Guidance: DER in Dynamic Load Models

• Differentiation of U-DER vs. R-DER

• Modeling thresholds determined by PC or TP

• Explicit modeling of U-DER• Inclusion of R-DER in powerflow

load records


Modeling Guidance: DER in Dynamic Load Models

• Coordination with DERTF leadership on direction Recommended to proceed with guidance; Topic very focused on one aspect of DER (dynamic load modeling) Being developed by SMEs and utility transmission planners

• Reviewed and accepted by SAMS• Seeking PC input and reviewers to finalize guidance


ERSWG and DERTF Update

Brian Evans-Mongeon (ERSWG Co-Chair)Planning and Operating Committee MeetingsSeptember 13-14, 2016


Essential Reliability Services Working Group (ERSWG)


ERSWG 2016 & 2017 Deliverables

2016 Deliverables:• Assist in process development for Approved measures• Whitepaper on methodology for ERS Measures Sufficiency

Guidelines

2017 Deliverable:• Final Report on ERS Measure Sufficiency Guidelines


ERS Schedule

Date Action Business Days Alloted Previously

Business Days Allotted with New Schedule

August 2 – 3 DER Workshop, Atlanta GA 0 2August 3 – 4 ERSWG/DERTF Working Meeting 0 2

August 4 - September 6 Sufficiency Guideline Whitepaper Development (Includes Labor Day) 30 30

September 6 - 20 Sufficiency Guideline Whitepaper Draft sent to ERSWG and DERTF members for review 15 15

September 13-15 September OC, PC & ERSWG MeetingSeptember 20 – 30 Incorporate ERSWG and DERTF members’ comments 0 8

October 3 - 11 NERC Admin Formatting Review (Includes Columbus Day Holiday) 0 6

October 12 Sufficiency Guideline Whitepaper draft sent to OC and PC for review 0 0

October 12 - 28 OC and PC review period 8 17

October 12 - 28 Send to NERC Management for initial review 0 17

October 31 - November 4 ERSWG incorporates OC and PC, and NERC Management comments and respond to OC and PC members 5 5

November 4 - 25 NERC Admin final format review/Buffer 0 21

11/28/2016 - December 13 ERSWG send report to PC and OC for review before face to face meeting 8 11

November 28 - December 13 Sufficiency Guideline Whitepaper sent to NERC Executive Management, MRC - in parallel to PC/OC 4 11

December 13 – 16 PC and OC Acceptance at Dec Meetings. AND ERSWG responds to feedback from NERC Executive Management, PC and MRC 0 4

December 15 (awaiting confirmation) Target Posting on nerc.com


ERS – Frequency Support

• 2016 Whitepaper focuses on Measures 1, 2 and 3 Two step process for evaluating inertia o Top down: determine synchronous inertia needed to avoid UFLSo Bottom up: verify actual system dispatch for more accuracy

Potential mitigation approaches for low system inertia

• 2017 Report will add guidelines for Measure 4


ERS – Ramping

• Process for Measure 6: Pre-screening evaluation analyzes system conditions, resource

mix and non-dispatchable resources to:o Identify hours where dispatchable resources are a small percentage of total

resourceso Typically these are low load hours with high levels of non-dispatchable resources

and hours with large ramps If pre-screen indicates a concern, communicate with NERC RAS

and NERC RS, conduct a more detailed review of CPS1 scores to determine whether it is a ramping issue NERC RS developing a parallel screening process


ERS – Voltage Support

• Process for Measure 7: Concluding that “reactive power sufficiency” will vary based

on sub-areas and local system characteristics:o Evaluation needs to be done on relevant sub-areaso Aspects to consider as PC/TP/RC/TO work together in defining

sub-areas and sufficiency measures that are appropriate for each sub-area

Refers to “NERC Reliability Guideline: Reactive Power Planning and Operations” and includes a high-level summary


Next Activities

• Face-to-face meeting following OC/PC to review sufficiency guidelines and review draft report

• Draft report will be sent to OC/PC by October 12• Continue discussion of data collection efforts for ERS measures


Distributed Energy Resources Task Force (DERTF)


DERTF 2016 & 2017 Deliverables

2016 Deliverables:• Identify and preliminarily assess distributed energy resource

impacts• DERTF Report by year-end

2017 Deliverables:• Present report to Board of Trustees


DERTF schedule

Date Action Business Days Alloted Previously

Business Days Allotted with New Schedule

August 2 – 3 DER Workshop, Atlanta GA 0 2August 3 – 4 ERSWG/DERTF Working Meeting 0 2August 4 - September 6 DERTF Report Development (Includes Labor Day) 30 30

September 6 - 20 DERTF Draft Report sent to ERSWG and DERTF members for review 15 15

September 13-15 September OC, PC & ERSWG MeetingSeptember 20 – 30 Incorporate ERSWG and DERTF members’ comments 0 8

October 3 - 11 NERC Admin Formatting Review (Includes Columbus Day Holiday) 0 6

October 12 DERTF draft Report sent to OC and PC for review 0 0October 12 - 28 OC and PC review period 8 17October 12 - 28 Send to NERC Management for initial review 0 17

October 31 - November 4 ERSWG and DERTF incorporates OC and PC, and NERC Management comments and respond to OC and PC members 5 5

4-Nov Send report to NERC Publications Department for first Review 0 0

November 4 - 14 NERC Publications first Review 8 5

November 15 - 25 ERSWG and DERTF responds to Publications comments + Buffer (Includes Thanksgiving Break) 0 7

11/28/2016 - December 13 ERSWG and DERTF send report to PC and OC for review before face to face meeting 8 11

November 28 - December 13 DERTF Report sent to NERC Executive Management, MRC - in parallel to PC/OC 4 11

December 13 – 16 PC and OC Acceptance at Dec Meetings. AND ERSWG and DERTF responds to feedback from NERC Executive Management, PC and MRC 0 4

19-Dec Send to NERC Publications for Final Review December 19 - January 13, 2017 NERC Publications Final Review 0 201/16/2017 DERTF Final Report sent to NERC Board of TrusteesJanuary 16 - 31, 2017 NERC Board of Trustees review period 6 11

1/31/2017 (Awaiting Confirmation) NERC Board of Trustees to approve the DERTF Report

Awaiting Confirmation Target Release


NERC DER Workshop Update

• August 2 & 3, 2016 Atlanta• Originally scoped for 60 participants, had over 175 registrants• Key speakers: Gerry Cauley, Mark Lauby, Allen Mosher of

APPA as Keynote Speaker• 4 Panels: Aligning the Definition, Observability and Controls,

Load & Gen Modeling, Voltage and Frequency Performance• Questions abound, moderators never had to ask prepared

questions• Participants were engaged, written comments on construct of

the work scope and tasks assigned to the task force

Materials and Video link to the recording posted on nerc.com ERS/DER site: HERE

http://www.nerc.com/comm/Other/Pages/Essential-Reliability-Services-Task-Force-(ERSTF).aspx


• How should DER be included in planning and operating models?• What level of control is needed for reliable system operations?• What level of visibility do system operators require?• How can DER characteristics contribute to or impact the

reliability of the bulk power system? More than load modifiers Impacts dynamic character of the power system

• What does the ERO need to consider?

DERTF Report – Key Areas of Focus


Next Activities

• Face-to-face meeting following OC/PC to review draft report• Draft report will be sent to OC/PC by October 12• Continue final development of the report to be presented for

standing committees acceptance in December 2016


Reliability GuidelinePMU Placement and InstallationModeling DER in Dynamic Load ModelsPC Approval for Industry Comment Period



Reliability Guideline:PMU Placement and Installation


• PMU Installation Equipment considerations Digital relays and stand-alone devices Communications and IT Data quality

• Data storage and retrieval

Guideline Overview

Field PMU Reference PMU

PDC

Field Location Central Location

Network

Table 1: Example Comparison of Utility Data Historians

SCADA Historian System PMU Historian System

Number Tags File Size Archive Frequency Number Tags File Size Archive Frequency

100,000 8 GB 8 – 10 days 1,500 8 GB 6 – 8 hours


• Real-Time Tools Considerations State estimation Oscillation monitoring and analysis Subsynchronous resonance & control interaction Angle difference monitoring Voltage stability Transmission interfaces Remedial action schemes Wide-area visualization & alarming Variable energy resource integration Islanding detection and monitoring Blackstart & system restoration

Guideline Overview


• Offline Analysis Considerations Power plant model validation System model validation Load model validation Disturbance monitoring Event analysis Frequency response analysis

• Prioritization Based on Application• Interconnection Requirements References

Guideline Overview


Reliability Guideline:Modeling DER in Dynamic Load Models


Guideline Overview

Table 1: Example of U-DER and R-DER Requirements

Criteria Description Threshold

U-DER Modeling Gross aggregate nameplate rating of an individual U-DER facility directly connected to the distribution bus or interconnected to the distribution bus through a dedicated, non-load serving feeder

___ MVA

R-DER Modeling Gross aggregate nameplate rating of all connected R-DER resources that offset customer load including residential, commercial, and industrial customers

___ MVA


Guideline Overview

Topics addressed:• Differentiating between DER for purposes of modeling• Accounting for DER in powerflow records• Linking R-DER to powerflow records• Explicit modeling of U-DER• Adaptation to specific systems (modeling thresholds)• Coordination with DERTF (mentioned in guideline)


• Sept ‘15-June ‘16 Development of draft guideline• June 29 SMS Approved draft guideline• Sept 14 PC approval for industry comment period• Sept 19-Nov 4 Industry Comment Period • Nov 5-Dec 1 Response to industry comments• Dec 13 PC final approval

Development Timeline


Reliability GuidelinePower Plant Model Verification using PMUsPC Final Approval



• Document Covers: Fundamental need for representative models Power Plant Model Verification (PPMV) Offline Baseline Testing for pro forma Model Online Performance Monitoring Process for Model Validation Value Proposition for Disturbance-Based Verification Related NERC Reliability Standards Performing PMU-Based Model Verificationo Procedure Overviewo Measurement & Modeling Considerationso Event Selection

Disturbance-Based Verification Examples Library Appendix – Software Tools Guidelines

Guideline Overview


• Sept ‘15-Apr ‘16 Development of draft guideline• June 7-8 PC approval for industry comment period• June 20-Aug 12 Industry comment period• Aug 13-Aug 24 SMS response to industry comments

PPMV SME review NERC Legal review

• Sept 2016 PC final approval



• 90 comments from 15 commenters Responses drafted by NERC Staff, NERC SMS members, and PPMV SMEs Responses and final draft guideline reviewed by NERC Legal

• Noteworthy Comments

Response to Comments

Comment Topic Response

Creating “de facto” standards or practices Guidelines are recommended practices and bear no binding norms or parameters by which compliance to standards is monitored or enforced. Ensure no conflicts with MOD standards; guideline language modified to stress this is one of multiple options for verification.

Selection and number of events Guideline provides examples, updated guideline to reflect that these may differ by entity based on event occurrences.


Response to Comments

Comment Topic Response

Comments, questions, and more referenceto baseline testing

Out of scope of guideline (disturbance-based verification); provided a table as an example; added IEEE references to WG reports and IEEE Recommended Practices.

Responsibility of entities for feedback loop and collaborative approach

Vetted by NERC Legal, “softened” languageto recommend collaboration with no emphasis on any requirements.

How to tune the model and accuracy tolerance

Industry is not ready to recommend a tolerance level for accuracy. Recommend engineering judgment.


• Addressed every comment received by industry• Revisions: No substantial redirection or revisions to guideline Terminology modifications, additions, footnotes added, etc. to ensure

clarity on questions and comments received.

• NERC SMS is requesting final PC approval for the Reliability Guideline for Power Plant Model Verification using PMUs

Approval Item


Load Modeling Technical Reference DocumentRyan D. Quint, NERCNERC Planning Committee MeetingSeptember 13-14 2016


• Document covers: Changing Nature of Electrical Loads Electrical End-Use Load Types Collecting Distribution-Level Data Load Composition Data Development

Technical Reference Overview


• Document covers: Laboratory and Simulation Testing Field Measurements Composite Load Modeling Guidance System Analysis Considerations Modeling Improvements Load Model Datasets & Parameters

Technical Reference Overview


• NERC held the FIDVR & Dynamic Load Modeling Workshop in Alexandria, VA in September 2015 125 attendees from many sectors of industry – utility and manufacturing Led to development of NERC Load Modeling Task Force (LMTF)

• Technical Reference Document captures key technical takeaways from workshop and subsequent work in LMTF Provides landscape overview of dynamic load modeling Concurrent and subsequent work in LMTF addressing topics in detail

Technical Reference Purpose


• Sept ‘15-May ‘16 Development of technical reference doc• June 17 Approved by LMTF• July 13 Approved by SAMS• Sept 14 Identify PC reviewers• Sept 19-Oct 14 PC review period• Oct 15-Nov 15 Final draft development• December PC Final PC approval• NERC LMTF seeking approval of technical reference document

following review by volunteer PC reviewers Technical content developed by LMTF, reviewed and approved by SAMS Guideline does not make recommendations, only provides technical

content



Oscillation Analysis UpdateData Requests #1

Ryan Quint, Mohamed Osman, Deepak Ramasubramanian, NERCNERC Planning Committee MeetingSeptember 13-14 2016


• Objective: understand modal characteristics of each interconnection using high-resolution, time-sync’d data Mode shape, mode frequencies, mode damping ratio

• Provide utility industry with better fundamental understanding of inter-area modes and forced oscillations on the BPS

• Use actual data to characterize system; possibly benchmark with model-based approaches

• Explore oscillation analysis tools available to industry

Source: Montana Tech

Oscillation Analysis

http://www.nerc.com/comm/PC/Synchronized%20Measurement%20Subcommittee/SMS%20-%20Interconnection-Wide%20Oscillation%20Baselining%20and%20Data%20Collection%20Scope%20Document%20-%2012-14-2015.pdf


• Data requests go out to the RCs as applicable events occur based on NERC SMS and SME engineering judgment.

Regions apprised of request via ERO-RAPA group

• Inter-Area Oscillations: 2 data requests for each interconnection (Western, Eastern, and ERCOT) triggered by system disturbance

• Forced Oscillations: 1 data request for the EI Grand Gulf event• NERC Staff has done some preliminary analysis of Event #1 and

shared that analysis with the NERC SMS (including SMEs on this topic)

Status Update


Eastern Interconnection2016-02-01 14:50:00 UTC

• 970 MW unit trip ISO-NE PJM Southern Company MISO NYISO – Time Shifted TVA – Not 30 sps FRCC – PDC down SPP – no data

• 8 second ringdown• 60 signals selected for

quality and wide-area view

752 753 754 755 756 757 758 759

59.945

59.95

59.955

59.96

59.965

59.97

59.975

59.98

59.985

59.99

59.995


VARPRO Tool - Open Source


Mode Shape, FFT, Results

0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2

Frequency [Hz]

0.2

0.4

0.6

0.8

1

1.2

1.4

fft

• Table of modes, filter based on: Frequencies of interest Reasonable damping

ratio Energy in mode

• 0.25 Hz @ 10+%• 0.65 Hz @ 8%• 0.55 Hz @ 10+%• 0.73 Hz @ 4%• 0.88 Hz @11%


Mode Shape for 0.25 Hz Mode

0.002

0.004

0.006

0.008

0.01

30

210

60

240

90

270

120

300

150

330

180 0

SoCo

PA/NJ

ISO-NE

VA/MD/TN/KY/etc.

MISO


Western Interconnection2016-01-21 08:55:00 UTC

• 1468 MW unit trip in Montana area• Peak Reliability data Comprehensive wide-area coverage But California data of poor quality


Mode shape for 0.4036 Hz


Mode shape for 0.8339 Hz


Measurement Simulation

Measurement vs Simulation

Close to event

Measurement

Time Time

Freq

uenc

y

Freq

uenc

y


Reportedfrequency

Derivedfrequency

Event on 01-21-2016

Event on 01-21-2016

Reported vs Derived FrequencyExample

*using 2-point derivative with 6-point median filter


Modes obtained

Measured frequency Derived frequency


Quarterly Update on NERC Reliability and Special Assessments Thomas ColemanDirector, Reliability Assessment Planning Committee Meeting, Phoenix, ArizonaSeptember 14, 2016


Core Reliability Assessment Program

Assessment Scope Periodicity Data Type/ Source

Advisory/ Coordinating

Group

Production Period

Technical Committee

Review

MRC/BOT Review

Long-Term • 10-Year resource assessment

• Emerging reliability issues

• 5-Year probabilistic assessment

Annual(Probabilistic assessment conducted biennially)

Resources, demand, and transmission projections /

Regional Entities

ReliabilityAssessment

Subcommittee, Planning Committee

Decemberto

December (13 months)

September -October

November -December

Summer • Resource assessment

• Seasonal operational issues

Annual Resource and demand

projections / Regional Entities


Subcommittee, Planning and

Operating Committees

March to

May (3 months)

May Approved by NERC

Winter • Resource assessment

• Seasonal operational issues

Annual Resource and demand

projections / Regional Entities


Subcommittee, Planning and

Operating Committees

September to

November (3 months)

November Approved by NERC

Special (Short and Long-Term)

• Topic-focused • Emerging issues

that require additional assessment

As Needed(2 to 4 per

year)

Area of focus will determine if additional

data is needed

Advisory Group to be established

under the Planning and/or Operating

Committees

3 to 12 months

2 to 4 weeks for comment and review; 1

week for acceptance

2-4 weeks for comment, review, and acceptance


Current Special Assessments Under Development

• NERC Special Assessment: Accommodating High Levels of Distributed Energy Resources OC/PC review – September through December Board acceptance – February 2017

• NERC Special Assessment: Single Points of Failure on Natural Gas Infrastructure Impacts to BPS Reliability Targeting Q2 2017 for Board acceptance

• NERC Special Assessment: Frequency Response Assessment of the Eastern Interconnection: Scenario Analysis of the Changing Resource Mix Work in progress; publishing schedule not set


Special Assessment Topics for Consideration/Additional Suggestions

• August 2017 Solar Eclipse• Variable Resource Curtailments• Accelerated Nuclear Retirements• Off-Peak Load Seasonal Assessment• Natural Gas Single Point of Failure Analysis

PC Feedback and Input is Greatly Appreciated!


General Feedback on Core Reliability Assessments - Roundtable

• Long-Term Reliability Assessment• Seasonal Reliability Assessments


Documents

Frequency Response Initiative Generator Event Survey › comm › PC › Agenda Highlights and... · Frequency Response Initiative Generator Event Survey. Troy Blalock, NERC RS Chairman