Midwest Reliability Organization 2018 Spring Reliability ... 23, 2018 Sprin… · 2018 MRO Spring...

May 23, 2018 Midwest Reliability Organization

380 St. Peter Street, Suite 800 Saint Paul, MN 55102

Midwest Reliability Organization 2018 Spring Reliability Conference

CLARITY ▪ ASSURANCE ▪ RESULTS of 78

2018 MRO Spring Reliability Conference Logistics Wednesday, May 23, 2018

Breakfast A catered hot breakfast will be provided from 7:00 a.m. – 8:00 a.m. in the lounge of the conference area. If you have any dietary restrictions, please see a person at the registration table or the server in the lounge.

Beverages Beverages will be available in the conference room, as well as in the lounge. Please help yourself.

Lunch A catered lunch will be provided. If you have any dietary restrictions, please see a person at the registration table or the server in the lounge. Please follow the emcee’s instructions for dismissal to lunch.

Restrooms Restrooms are located outside of the conference room, as well as on floors 7 and 10. If you choose to use a restroom on another floor, please take the elevators. The staircases only open on the first floor.

Conference Etiquette As a courtesy to presenters and conference participants, please observe the following rules of conference etiquette: • Silence all of your electronic devices prior to sessions• Please defer to speakers’ preferences for questions;

however, when you ask your question, please wait fora microphone runner to come to you first, for thebenefit of those that are located in the overflow room

• Be seated prior to the beginning of each session

Name Badges Please wear your name badge at all times.

Conference Evaluation Your feedback is appreciated; a feedback form is included in this packet. Please complete the form and leave it at your seat or place it in the feedback form box at the registration table.

Luggage Storage for any size travel luggage can be found in MRO’s lobby by the registration desk. Please ask MRO staff at the registration desk for assistance.

Lost and Found An MRO representative will always be in the meeting room; however, personal belongings are left at your own risk. If you find or lose an item, please visit the registration desk. After the conference, please contact Chris Adam at: [email protected]

Power Power will be supplied at the tables. Please refrain from plugging into floor outlets to minimize the hazard from tripping. Power strips are also available at the two counters within the conferencing space.

Videos/Photographs MRO may take videos or photos of its conferences and events for use on the MRO website or in MRO publications or other media produced by MRO. MRO reserves the right to use any image taken at any event sponsored by MRO, without the express written permission of those individuals included within the photograph and/or video. To ensure the privacy of conference attendees, images will not be identified using names or personal identifying information without the express written approval from the individual shown. If you do not wish to have your image taken for future publication, please notify MRO event staff. By participating in this MRO event or by failing to notify MRO of your desire to not have your image taken by MRO, you are agreeing to allow MRO to use your image as described. Thank you for your understanding and cooperation!

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mailto:[email protected]

2018 MRO Spring Reliability Conference Agenda Wednesday, May 23, 2018

7:00 am – 8:00 am Registration & Breakfast 8:00 am – 8:10 am Welcome

Sara Patrick, Interim President &CEO, MRO

8:10 am - 8:20 am Introduction and Conference Logistics

Emcee: John Seidel, MRO

8:20 am – 9:00 am Keynote Speaker- Opening Comments and NERC Reliability Issues Steering Committee

Lloyd Linke, MRO Board Member and NERC Operating Committee Chair

9:00 am – 9:45 am Substation Equipment Failure Modes and Mechanisms

Richard Hackman, Sr. Reliability Advisor, Reliability and Risk Management, NERC

9:45 am – 10:00 am Morning Networking Break 10:00 am – 10:45 am Transmission System High Voltage Conditions and Mitigations

Chuck Lawrence, Planning Compliance Manager, American Transmission Company

10:45 am – 11:15 am Real Time Assessment

Doug Peterchuck, Manager, Transmission Operations, Omaha Public Power District

11:15 am – 12:00 pm EMS Applications and the Impact of Unavailability

Venkat Tirupati, Manager, Market Systems, Colorado River Authority

12:00 pm – 1:00 pm Lunch/Networking 1:00 pm – 1:45 pm Managing Generation Availability in Real Time

Kevin Vannoy, Director of Market Design, Midcontinent ISO

1:45 pm – 2:30 pm SPP-RTO: Operational Characteristics

Derek Hawkins, Supervisor, Real-time &Current-day Engineering, Southwest Power Pool RTO

2:30 pm – 2:45 pm Afternoon Break 2:45 pm – 4:00 pm Human Performance and Skilled Workforce

James Merlo, Vice President of Reliability and Risk Management, NERC

4:00 pm – 4:30 pm Wrap Up/Questions/Feedback Forms/Adjourn

Conference Agenda

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MRO Spring Reliability Conference Agenda Wednesday, May 23, 2018

Welcome

JohnSeidel

2018SpringReliabilityConferenceEmceeSeniorManagerofOperationsandReliability,MRO

[email protected]

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KeynoteSpeaker‐OpeningCommentsandNERCReliabilityIssuesSteeringCommittee

LloydLinke

VicePresidentofOperations,UpperGreatPlainsRegionofWAPA

[email protected]

Lloyd Linke is currently Western Area Power Administration’s Vice President of Operations for the Upper Great Plains Region. In his current position he is responsible for the operation, planning of the Upper Great Plains Region’s transmission.

Lloyd served as the Administrator of the Alaska Power Administration prior to returning to Western. In this position he served as CEO and was responsible for all functions and business lines of the Alaska Power Administration. He has worked in several areas within the electrical power industry including maintenance, construction, power billing, marketing, and operations of high voltage transmission systems and hydroelectric generation facilities.

Lloyd has over thirty-five years of experience in the electrical power industry and received a degree in Electrical and Electronics Engineering from the North Dakota State University. He currently is a director on the Midwest Reliability Organization Board; on the NERC Members Representative Committee, the Chair of the NERC Operating Committee and member of the Southwest Power Pool Markets and Operations Policy Committee. He has served as a Board member of the Pacific Northwest Security Coordinator, Chair of the MAPP Reliability Committee and Regional Reliability Committee, member of MRO initial Bylaws Committee and MRO transition team.

Lloyd is happily married, with two wonderful children, and lives in Watertown, SD.

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Subject, Office or event

Opening Comments and RISCLloyd Linke, VP of Operations for UGPR

May 23, 2018

MRO Reliability Conference

St Paul, MN


What is Western?

2


Part of DOE

• One of 4 power marketing administrations, under DOE

• Wholesale electricity supplier

• 457 long‐term/firm power preference customers when agency formed in 1977

• Nearly 700 customers today

3

2018 MRO Spring Reliability Conference

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A PMA

4


WAPA’s Regions

5


The Upper Great Plains Region

Covers Six North Central States - South Dakota, North Dakota, Montana, Minnesota, Iowa, Nebraska

378,000 square mile Service Territory

7750 miles of Western transmission lines. Operate approx. 2800 miles of transmission owned by others.

250+ Western owned and non Western owned Substations and Taps.

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Where UGP Gets Its Power …. Pick‐Sloan Missouri Basin, Eastern Division

7


NERC Reliability Issues Steering Committee (RISC)• February 2012 Standards Process Input Group recommended formation of RISC

• RISC First public meeting on October 22, 2012

• Develop of framework for thinking about risk

• Using framework to prioritize set of risk areas where NERC could apply significant resources

• First report presented to NERC Board in February and August 2013

8


Reliability Risk Priorities Report

• Strategically defines and prioritizes risks to the reliable operation of the BPS

• Supports ERO Enterprise strategic and operational planning

• Key inputs• RISC subject matter expertise• Reliability Leadership Summit• FERC Technical Conference• Pulse Point Interviews• Review of NERC Technical Studies• DOE Grid Study

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Risk Profiles

10


Changing Resource Mix

• Continued to evolve with the addition of emerging technologies.

• May not have sufficient time to develop and deploy plans in response to reliability considerations resulting from the new resource mix.

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Bulk‐Power System Planning• Transitioning from centrally planned and constructed resources based on forecasted load to planning based on the integration of new resources and technologies.

• Lack of visibility, certainty, and speed that these resources are being integrated, planners may lack the ability to timely update or create system models and scenarios of potential future states toidentify system reliability needs, driving the need for more real‐time operating procedures.

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Resource Adequacy and Performance• The resource mix and its delivery is transforming from large, remotely‐located coal and nuclear‐fired power plants, towards gas‐fired, renewable energy, DER, and other emerging technologies.

• These changes are altering the operational characteristics of the grid and will challenge system planners and operators to maintain reliability.

• Failures to take into account these changes can lead to insufficient capacity, energy, and ERS to meet customer demands.

13


Increasing Complexity in Protection Control Systems• Failure to properly design, coordinate, commission, operate, maintain, prudently replace, and upgrade BPS control system could negatively impact system resilience and result in more frequent and wider‐spread outages.

• Asset management strategies are including greater amounts of digital network based controls for substation introducing cybersecurity risks.

14


Human Performance and Skilled Workforce• The BPS is becoming more complex and it will have difficulty staffing and maintaining necessary skilled workers.

• The addition of significant internal procedural controls needed to maintain compliance has brought additional complexity to many skilled worker positions.

• Inadequate human performance (HP) makes the grid more susceptible to both active and latent errors, negatively affecting reliability and may hamper an organization’s ability to identify and address precursor conditions to promote effective mitigation and behavior management.

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Loss of Situational Awareness

• Inadequate situational awareness can be a precursor or contributor to BPS events.

• Loss of situational awareness can also occur when control rooms are not staffed properly or operators do not have sufficient information and visibility to manage the grid in real‐time.

• Insufficient communication and data regarding neighboring entity’s operations is a risk as operators may act on incomplete information.

16


Extreme Natural Events

• Severe weather or other natural events are one of the leading causes of outages. Severe weather can cause BPS equipment damage, fuel limitations, and disruptions of voice and data communications, which can cause loss of load for an extended period.

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Physical Security Vulnerabilities

• Intentional damage, destruction, or disruption to facilities can cause localized to extensive interconnection‐wide BPS disruption potentially for an extended period.

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Cybersecurity Vulnerabilities

• Cybersecurity vulnerabilities can potentially result in loss of control or damage to BPS‐related voice communications, data, monitoring, protection and control systems, or tools.

• They can damage equipment, causing loss of situational awareness and, in extreme cases, can result in degradation of reliable operations to the BPS, including loss of load.

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Resilience Framework

• NERC Board asked RISC to:• Develop a common understanding and definition of the key elements of Bulk Power System (BPS) resilience

• Understand how key elements of BPS resilience fit in the existing ERO framework

• Evaluate whether additional steps are needed to address key elements of BPS resilience within the ERO framework

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Understanding and Defining Resilience

• National Infrastructure Advisory Council’s (NIAC’s) resilience framework• Robustness

• Absorbs shocks and continue operating• Resourcefulness

• Skillfully detect and manage a crisis as it unfolds

• Rapid Recovery• Get services back as quickly as possible in a coordinated and controlled

manner

• Adaptability• Incorporate lessons learned from past events to improve resilience

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Subject, Office or event 22

Bulk Power System Resilience*


RISC Next Steps

• Incorporate input from standing committees and recommendations from Members Representative Committee

• Monitor FERC proceedings

• RISC Webpage• https://www.nerc.com/comm/RISC/Pages/default.aspx

• RISC priority report• https://www.nerc.com/comm/RISC/Related%20Files%20DL/ERO‐Reliability‐_Risk_Priorities‐Report_Board_Accepted_February_2018.pdf

23

Subject, Office or event 24

Thank you


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SubstationEquipmentFailureModesandMechanisms

RichardHackmanSeniorReliabilityAdvisorofReliabilityandRiskManagement,NERC

[email protected]

Rick Hackman is with NERC Event Analysis, leading the Lessons Learned program and Failure Modes and Mechanisms development. Previously, he spent eight years with American Electric Power’s Transmission Substation Engineering and Regulatory Compliance groups. He built a complete Root Cause Training course with case studies and videos for AEP Transmission and NATF Operating Experience group. Before that, he had twenty-nine years of Nuclear Power experience including Licensed Reactor Operator, Radiochemist, Shift Technical Advisor, Nuclear Power Systems Trainer for Professionals, Engineering and Management, Contract Root Cause Analyst for Organizational, Management, Human Performance, and Equipment Failures, and Director Root Cause Analysis for Failure Prevention Incorporated. He wrote symptom based power plant equipment failure diagnostic assistance software for EPRI. He has a BS in Chemistry and Biology from Harding University Searcy, AR.

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Failed Substation EquipmentFailure Modes & Mechanisms

Rick Hackman, NERCMay 23, 2018

RELIABILITY | ACCOUNTABILITY2

NERC Event Analysis Website


NERC Event Analysis Website


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NERCTV

Placeholder slide for FMM Intro Video


Failure Modes and Mechanisms (FMMs)

Improve Equipment Reliability by Learning from Failures

• Failure Modes are what gets your attention

• Failure Mechanisms are how the equipment gets going on the path to a failure

• Equipment Failures have logical cause-and-effect relationships behind them.

• Physical Evidence Examination and Root Cause Analysis can reveal what Failure Mechanisms were involved.

• Aging is not a ‘cause.’ It is just a catch-all term for slow moving FailureMechanisms.

• Failure Mechanisms are detectable. Many can be stopped, or at least slowed down so they can be corrected before causing a failure.


Combine Failure Modes & Mechanisms w/Other EA Tools

• Improve “Addendum for Events with Failed Station Equipment”usefulness

• Capture Equipment FM&M data to discover trends and patterns just like Event Cause Codes

• Discover which FM&Ms impact Reliability most to help prioritize prevention efforts

• Develop Failure Mechanism detection methods to spot issues prior to failure

• Cross Reference FM&M with Lessons Learned (and vice versa)

• Provide a equipment failure analysis resource for engineers andfield workers

2018 Spring Reliability Conference

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Cause Code Tree Structure

Many people involved in the Event Analysis Program are already familiar with the Cause Codes used in Event Analysis

FMM allows more equipment -specific coding.

https://www.nerc.com/pa/rrm/ea/EA%20Program%20Document%20Library/CCAP_Manual_January_2018_Final_Posted.pdf


Addendum for Events with Failed Station Equipment

The Addendum for Events with Failed Station Equipment is being revised to capture FMM data.


New Draft Addendum for Events with Failed Station Equipment

Dropdown selections for Equipment Types and Failure Mechanisms


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Generic Failure Modes & Mechanisms Layout

OrOr

1

1

LL20180101


Bushing Failure Modes & Mechanisms

Developing issue often

visible prior to failure



Drought conditions can make this more likely

(accumulation not washed off by rain)



DRAFT Bushing Failure

Approaching loss of margin to failure may

be detectable by testing or Infrared

Oil leak may be externally

visible

AND

Connection to a higher voltage source, phase to phase fault, lightning…

An External Fault on a nearby phase can

create high voltage stress on another

Beyond Design Voltage Stress

External Fault

Contamination

OR

Contains conductive uric

acid and salts

Salt

Bird Excrement

Local Pollutants

UV

HeatErosion

(usually wind driven grit / sand)

Issues for Polymer Bushings

Ass

ists

Bu

ild-u

p

Cleaning Maintenance does not keep up with

contamination (maintenance not done, not

timely, or contaminant builds up abnormally fast)

OR

Issue for Porcelain or

Polymer Bushings

Glaze / Coating deterioration

(easier to stick to)

Snow / Ice Coating

Animal

Blown objects

Bridging by object

Thrown objects

Vegetation Growth

Grading Resistor or

Choke Failure

Mechanical Failure

ImpactMechanical

Overload

Cyclic Mechanical Loading

Blown objects

Gunshot

Vehicle

Attached Weight

Line Tension

Misaligned assembly

Strong Local Vibration

Source

Wind (line movement)

Seismic Events

Seismic Events

Work in Area

Bus / Device / Support / Other

Structure Foundation Movement / Failure

Erosion

Concrete Issues

Flooding

LTA site preparation

Seismic Events

LTA footing

LTA assembly

Generic Bushing Failure Modes and Mechanisms

This includes not just the end seals, but housing defects,

bushing failures, tank (can) weld failure,

internal pressure, or other boundary

failures.

May be caused by impact, assembly

error, corrosion, LTA material choice, temperature (or

pressure) extremes or cycling

Corrosion of metal if both are present

Machining / Cutting Oil has sometimes been found in

bushings – it slowly breaks down under voltage stress

providing carbon for tracking

Seal failure

Other Foreign Material

Salts

OR

OR

ORAND

Locally Available Contaminants /

Foreign Materials

Not Necessarily Locally Available Contaminants /

Foreign Materials

Moisture intrusion

Foreign Materials left

inside by Manufacturer

Material Defects from Manufacturer

While polymer or oil impregnated paper dielectric does not ‘leak out,’ it can wick up moisture from a seal failure, increase voltage stress, and become

contaminated by other foreign matter as well. See also transformer FMM for paper breakdown products.

Leakage of Dielectric(SF6 or Oil)

Voltage stress induces Breakdown of Carbon bearing

materials

Voltage stress lines up small amounts of conductive material deposits for tracking. Otherwise they would remain at point of

entry or fall by gravity…

Contamination of Solid Dielectric

(Paper or Plastic)

Increases Voltage Stress Locally

Conductive Material where it should not

be

Voltage Stress (Plenty is available when the device is in service)

Voids

GaseousByproducts

Tracking

Internal Fault

AND


SF6 Breaker Failure Modes & Mechanisms


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Oil Filled Transformer Failure Modes & MechanismsFu

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Vol

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Failure Modes & Mechanisms




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Surge Arrester Failure Modes & Mechanisms


Capacitor Bank Failure Modes & Mechanisms


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We need Reviewers, Improvement Ideas, Test & Rollout Champions

• Standardized FM&M diagrams anddefinitions

• FM&M User Guide Development

• Revised Addendum for Events with FailedStation Equipment

• Prioritize additional development

• Failure Mechanism Detection and PreventionMethodologies


FM&M Volunteers

• 1 from MRO

• 1 from BPA

• 1 from WAPA

We need more!

Volunteer Diagram Reviewers so far

Please volunteer to be part of this important industry reliability improvement process


Failed Station Equipment Failure Modes & Mechanisms

Send Failure Modes and Mechanisms Improvement Comments, Corrections, Additions, Lessons Learned, Diagnostics / Symptom Monitoring Ideas, & Failed Equipment Photos to:

Richard HackmanSr. Reliability Advisor, Reliability Risk ManagementNorth American Electric Reliability Corporation3353 Peachtree Road NE, Suite 600 – North TowerAtlanta, GA 30326404-446-9764 office | 404-576-5960 cellEmail [email protected]

Questions? Volunteers?


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TransmissionVoltageControlChallenges

ChuckLawrenceAmericanTransmissionCompany

[email protected]

Charles Lawrence is presently the Planning Compliance Manager at the American Transmission Company. He has over 35 years of experience in the electric utility industry, 20 years of experience in the Transmission Planning area, 12 years in the role of Principal Engineer, and 10 years of experience in NERC Transmission Planning compliance. Chuck has experience with performing multiple types of power system studies including steady state, dynamics, transients, harmonics, and frequency analysis. Over the years, he has been active in MRO, MISO, NATF, IEEE, EPRI, CEATI, PSERC, and ECAR activities, which included several publications. Chuck received his BSSE and MSEE degrees from Cleveland State University in Cleveland, Ohio and he is a Professional Engineer in the state of Wisconsin.

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atcllc.com

Transmission System High Voltage Conditions and Mitigations

Chuck Lawrence, Planning Compliance ManagerAmerican Transmission Company

May 23, 2018

atcllc.com 2

Overview

• Emerging Causes of Transmission System HighVoltage Conditions

• Identification of High Voltage Conditions and Causes

• Measures to Reduce Transmission System HighVoltage Levels

• Specific Examples


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• More miles of transmission lines• More leading power factor at distributioninterconnections

• Less local generation dispatched at low system loadlevels

• More local generation is being retired than is beinginstalled

Emerging Causes of Transmission System High Voltage Conditions


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Identification of High Voltage Conditions and Causes

• Collect and analyze various types of historicaldata.

• Collect selected types of transmission,generation and distribution equipmentinformation.

• Model and analyze the study area under lowarea load conditions.

4

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Collect and analyze various types of historical data.

• Collect and analyze two or more years of varioustypes of hourly historical voltage data in the selectedstudy area. These types of data include:

– Total of the real power load in the study area– Transmission voltages, reactive power flows, and

voltage regulating device operating actions– Distribution interconnection reactive power levels– Generation interconnection reactive power levels

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Collect selected types of equipment information.

Collect selected types of equipment information including:

– Transmission• Transformer no load tap settings

• Transformer LTC controller settings– Distribution

• Reactive power device operating modes – Generation

• Reactive power capability limits

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Model and analyze the study area under low area load conditions

• Model and analyze the study area under low areaload conditions with historically adjusted reactivepower operating levels

• Run simulations and monitor these voltage andreactive power values

– Transmission voltages, reactive power flows andvoltage regulating device operating actions

– Distribution interconnection reactive power levels– Generation interconnection reactive power levels

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Measures to Reduce Transmission System High Voltage Levels

• Change transformer no-load tap settings

• Change transformer LTC controller settings

• Change capacitor bank operating modes orsettings

• Add inductor (reactor) banks

8

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Specific Examples

• Scenario #1 – More miles of transmissionlines

• Scenario #2 – Local generation displaced byremote generation at low system loadconditions

• Scenario #3 – More leading power factor atdistribution interconnections

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atcllc.com

Scenario #1 – More miles of transmission lines

• In the past, there were fewer miles of 345 kV and 138 kV lines in an area and 138 kV system voltage levels needed to be raised. The 138 kV area voltages were raised by setting the no load taps of 345/138 kV transformers to the 2.5% boost position.

• Over time, more miles of 345 kV and 138 kV lines were added in the area and on occasion 138 kV area voltages became too high.

• Mitigating actions included: changing the no load tap settings of 345/138 kV transformers in the area to the nominal (neutral) tap position.

10

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Scenario #2 - Local generation displaced by remote generation at low system load conditions

• In the past, 138 kV system voltage levels in an area needed to be raised. The 138 kV area voltages were partly raised by setting the no load taps of 345/138 kV transformers to the 2.5% boost position and local generation helped regulate voltage at low system load conditions.

• Over time, remote generation displaced local generation at low system load conditions and 138 kV area voltages became too high.

• Mitigating actions included: changing the no load tap settings of 345/138 kV transformers in the area to the nominal (neutral) tap position and adding a local transmission inductor (reactor) bank.

11

atcllc.com

Scenario #3 - More leading power factor at distribution interconnections

• In the past, 69 kV system voltage levels in an area needed to be raised. The 69 kV area voltages were partly raised by setting the no load taps of 138/69 kV transformers to the 2.5% boost position and transmission, as well as distribution, capacitor banks were added to help regulate voltage at low system load conditions.

• Over time, the power factor of 69 kV distribution interconnections became more leading, particularly at low system load conditions.

• Mitigating actions included: changing the no load tap settings of 138/69 kV transformers to the nominal (neutral) position, changing the operating mode of distribution capacitor banks, and adding local transmission inductor (reactor) banks.

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Questions?



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Real Time Assessment Compliance Implementation Guidance

Doug Peterchuck

Manager, Transmission Operations, OPPD

[email protected]

Doug Peterchuck is currently the Manager of Transmission Operations at the Omaha Public Power District. Previous work at OPPD included being the Manager of Reliability Compliance for 6 years and was an engineer within System Protection for 10 years. Previous to OPPD, Doug worked within the Substation Department at MidAmerican Energy and within the Quality Control Department at the switchgear manufacturer E.A. Pedersen Company. Doug is currently a Municipal Sector voting member of the NERC Operating Committee. Doug earned his BSEE from Iowa State University in 1993, his MSEE from Kansas State University in 2000, and an MBA from the University of Nebraska-Omaha in 2015. Doug is a registered professional engineer in the State of Nebraska and is a member of IEEE.

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NERC OCReal-time Assessment Implementation GuidanceDoug Peterchuck – NERC OC and RTATF ChairMay 23rd, 2018

RTA Implementation Guidance

NERC OC Motion to form a Task Force to

1) Investigate the compliance andreliability concerns regarding a Real‐timeAssessment (RTA) per TOP‐001‐3 R13and IRO‐008‐2 R4

2) Discuss how RTAs are completed whenthere is a loss (partial and full) of EMS

3) Develop any necessary guidance

Real-time Assessment Task Force

• Doug Peterchuck, Omaha Public Power District –RTATF Chair• Doug Hils, Duke Energy• Paul Johnson, AEP•Michelle Rheault, Manitoba‐Hydro• Saad Malik, Peak Reliability• Alan Bern, Oncor• Stephen Solis, ERCOT• Rich Hydzik, Avista• Christopher Pilong, PJM• Vinit Gupta, ITC• Steve Crutchfield, NERC ‐ Manager of OC Support• Craig Struck, NERC


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•Guidance documents cannot change the scope orpurpose of the requirements of a standard.

• The contents of guidance are not the only way tocomply with a standard.

• Provide specific examples of complying with a specific requirement, otherwise Compliance Guidance approval will be denied

Principles for Compliance Guidance

•CMEP Practice Guides provide direction to EROEnterprise CMEP staff on executing compliance and enforcement activities

• Registered entities can rely upon the examples and be reasonably assured that compliance requirements willbe met with the understanding that compliancedeterminations depend on facts, circumstances, and system configurations.

Compliance Guidance Policy


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https://www.nerc.com/pa/comp/guidance/DraftImplementationGuidanceDL/TOP-001-3%20R13%20and%20IRO-008-2%20R4%20Real%20Time%20Assessment.pdf

RTA Compliance Guidance

Outline of RTA Implementation Guideline

• RTA Definition• RTA Under “Normal” Conditions• RTA with Loss of State Estimator/Security

Analysis• RTA – Complete Loss of EMS


RTA Definition“Evaluation of the system conditions using Real‐time data to assess existing (pre‐Contingency) and potential (post‐Contingency) operating conditions..”

• Definition does not describe “how” to dothis

• An Entity should consider developingprocesses defining how an RTA isperformed


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RTA Definition“…inputs including…known Protection System and Special Protection System status…”

• The paper breaks down ProtectionSystems and Special Protection Systems(RAS)


RTA Under “Normal” Conditions• Real‐time data monitoring (SCADA)‐ Alarming (Analogs, Digitals, etc.)

• Real‐time Contingency Analysis (RTCA)‐ Self‐produced or use of 3rd party

• Use of Line Outage Distribution Factors• Off‐line studies (Using Real‐time data and

reflecting System Conditions)• Monitoring of Protection Systems and RAS


RTA – Loss of State Estimator/RTCA• Real‐time data monitoring (SCADA)‐ Alarming (Analog, Digitals, SE Status, etc.)

• RTCA (Via 3rd Party Results)• Use of Line Outage Distribution Factors• Off‐line studies (Using Real‐time data and

reflect actual System Conditions)• Monitoring of Protection System/RAS• No System Changes

‐ Referenced within Rationale of Standard‐ Should define limits within Op Plan


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RTA – Complete Loss of EMS• EOP‐008‐2 R1.5 does not exempt an

entity from completing a 30‐minute RTA• Off‐line studies or applications‐ How do you supplement with Real‐

time Data and ensure the study is reflective of Real‐time Conditions

• Communication and agreements with RCsand/or neighboring TOPs


Areas of Emphasis from FERC/NERC/REs• Applicable entity must show that an RTA

was completed once every 30 minutes –In all situations

• When using offline studies to complete anRTA, the following must be met:‐ Based off Real‐time data‐ “Studies” should represent Real‐timesystem conditions


Areas of Emphasis from FERC/NERC/REs• When using a 3rd Party to complete an

RTA, an agreement should be createdbetween the entities

• Unless a Compliance Agreement (e.g.CFR) is in place, burden of proof is stillapplicable TOP


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Questions?



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EMS Applications and the Impact of Unavailability

Venkat Tirupati Manager, Market Systems, Colorado River Authority

[email protected]

Venkat Tirupati is currently the Manager of Market Systems at Lower Colorado River Authority (LCRA) in Austin, TX. He serves a team that is responsible for Operations, Administration & Maintenance of Generation Management System (GMS) and several mission/business critical ERCOT Market Applications. Previously at LCRA, he was the Supervisor of EMS and Advanced Applications, serving a team responsible for all things EMS. He is also a Cyber Security Coordinator, ensuring compliance to LCRA Cyber policies and procedures. He has previously worked as Senior Reliability Engineer in the Reliability Risk Management Group at NERC in Atlanta, GA and as a Senior Software Applications Engineer at Siemens Smart Grid Division in Minneapolis, MN. Venkat’s interests include IT/OT Line of Business systems architecture, design and support and also Power Systems Engineering.

Venkat earned his Bachelor of Engineering in Electrical Engineering from University of Mumbai, India and a Master of Science in Electrical Engineering from Illinois Institute of Technology, Chicago.

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EMS UNAVAILABILITY – RISK AND MITIGATION STRATEGIES

VENKAT TIRUPATI

MAY 23, 2018

Agenda

• Intro to Energy Management System (EMS)

• Risk in losing EMS

• Risk mitigation strategies

• Planning Restoration Absent SCADA or EMS

2

• Server Infrastructure- SCADA FEP/DAC

- ICCP

- Application

• Network Equipment- Firewalls/Switches

• Workstations/Consoles

• Communication Links

• Remote Terminal Unit

Components of EMS

3

• Software Applications

• Reliability Real-Time Tools


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Availability of EMS

• Extremely reliable – 99.99% but….

• Outages increase the risk to reliability of grid

• Several failure modes possible

• ERO Event Analysis Process (EAP) since 2010

• Average Restoration time of 60 mins

• Lots of Lessons Learned

4

Unavailability of EMS – Risk to Reliability

• Loss of Situational Awareness

• Alarms/Real Time Calculations

• Loss of ability to remotely control

• Loss of Real Time Reliability Tools

• Potential Market Implications

• Impact on field work/schedules

5

EAP Category 1h EventLoss of monitoring or control at a Control Center such that it significantly affects the entity’s ability to make operating decisions for 30 continuous minutes or more.

Some examples that should be considered for EA reporting include but are not limited to the following:

i. Loss of operator ability to remotely monitor or control BES elements

ii. Loss of communications from SCADA Remote Terminal Units (RTU)

iii. Unavailability of ICCP links, which reduces BES visibility

iv. Loss of the ability to remotely monitor and control generating units via AGC

v. Unacceptable state estimator or real time contingency analysis solutions

6


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EAP Category 1 (All vs. EMS Events)

7

8

*318 EMS events reported between October 2013 and April 2017

Contributors to Loss of EMS

9


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Mitigation – Systems

10

• Pro-Active rather than being Reactive

• Architecture/Design

• Application/Server/Switches/Firewalls Backups

• Monitoring – Apps, Servers, network etc.

• Testing – after patching/fixes/features

• Disaster Recovery Test

• Good relationship with vendors

• Relevant Training

Mitigation – System Operations

• Get help from neighbors/RC

• Dispatch folks to key substations

• Conservative operations

• Plans in place for generation units

• Various means of communication

• Mock Drills

11

Mitigation – Real Time Tools

• Overlapping network models

• Offline studies

• PMU tools

• Simulator Tools

12


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Planning Restoration Absent SCADA or EMS

• Planning for backup communications measures

• Planning for personnel support during system restorationabsent SCADA

• Planning backup power supplies for an extended period oftime

• Analysis tools for system restoration.

• Incorporating loss of SCADA or EMS scenarios in systemrestoration training

13

Reference Documents

• Risks and Mitigations for Losing EMS Functions

• https://www.nerc.com/comm/OC/ReferenceDocumentsDL/Risks_and_Mitigations_for_Losing_EMS_Functions_Reference_Document_20171212.pdf

• Planning Restoration Absent SCADA or EMSReport

• https://www.ferc.gov/legal/staff-reports/2017/06-09-17-FERC-NERC-Report.pdf

14

THANK YOU

[email protected]

15


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ManagingGenerationAvailabilityinRealTime

KevinVannoyDirectorofMarketDesigns,MidcontinentISO

[email protected]

Kevin Vannoy has over twenty-three years of Management and Consulting experience in the electric utility industry, including Regional Transmission Organizations, and regulated and deregulated markets. He has been with the Midcontinent Independent System Operator (MISO) since 2005. He is currently MISO’s Director of Market Design.

He was MISO’s Director of Forward Operations Planning from June 2015 to September 2017, his responsibilities included; Transmission and Generation Outage Coordination, Tariff Administration and Scheduling, Forecast Engineering and Seams Administration.

He was MISO’s Director of Market Administration from 2010 to June 2015, responsible for administering Auction Revenue Rights (“ARRs”), the Financial Transmission Rights (“FTR”) Markets, the Day-Ahead Energy and Operating Reserves Markets, Resource Adequacy including the Planning Resource Auction, Forecast Engineering as well as administering for the Forward Reliability Assessment Commitment and Real-Time Ex-Post Locational Marginal Pricing functions.

Kevin managed Market Services starting in 2005 following the launch of the Midwest Energy Markets. He led Market Quality and Dispute Resolution, Market Settlements, Tariff Pricing and Transmission Settlements until 2010.

Kevin has been involved with numerous Market development and improvement initiatives at MISO, including the Ancillary Services Markets implementation, Revenue Sufficiency Guarantee Allocation Redesign, Financial Transmission Rights Funding efforts, Transmission Multi-Value Project Auction Revenue Rights Allocation, Annual Resource Adequacy Auctions, and Extended Locational Marginal Pricing.

Kevin holds a Bachelor of Science Degree in Civil Engineering from the University of Florida. Prior to joining MISO, he held management roles with both the Structure Consulting Group LLC in their Regional Transmission Organization Consulting Practice, and Accenture (formerly Andersen Consulting) in their Utilities Industry Practice. Prior to joining Andersen Consulting in 1995, he served as a Commissioned Officer in the United States Navy.

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MRO Spring Reliability ConferenceMay 23, 2018

Kevin Vannoy, Director Market Design

Ensuring Resource Availability meets

Need (RAN) in MISO

Purpose & Key Takeaways

Key Takeaways:

• MISO has identified five trendsimpacting the reliable conversion ofcommitted capacity to energy

• The RAN initiative will assess the needfor enhancements to tools andprocesses to ensure adequacy eachday in line with planning criteria

Purpose: Discuss MISO’s Resource

Availability and Need (RAN) Initiative

Combined effect of five emerging trends have challenged the reliable conversion of committed capacity to energy across all

hours of the year in line with planning criteria

Key industry trends

• Aging and retirement of theportfolio’s generating units

• Outage correlation

• Growth in demand side and otheremergency-only capacity as a percent of the overall portfolio

• Growing reliance on intermittentor unscheduled resources

• Growth of variable energyresources as a major element ofthe fleet

Increase transparency of resource availability & need

Refine resource availability requirements

Improve price signals

Areas for improvement in MISO processes

3


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Less energy available each succeeding year combined with increased supply and demand volatility have led to increasing

reliance on non-firm and emergency energy resources

140

150

GW

130

120

110

100

90

80

70

60J‐16 F‐16 M‐16 A‐16 M‐16 J‐16 J‐16 A‐16 S‐16 O‐16 N‐16 D‐16 J‐17 F‐17 M‐17 A‐17 M‐17 J‐17 J‐17 A‐17 S‐17

EcoMax no Wind Wind NSI Emerg. Range AME Peak Load

Lower MWoffers for peaks after Winter 2016

4

Less energy available each succeeding year resulting fromaging fleet and retirements

• Higher outages

• Lower average energy offersPlanning

Year

Average Energy

Offers (MWs)

Avg. Outages

(MWs)

2014/15 126,400 16,800

2015/16 125,100 18,400

2016/17 117,100 22,600

YearCombined Rate

Eq. Planned Outage Factor

Eq. Maintenance Outage Factor

2011 5.34% 4.31% 1.03%

2012 5.58% 4.21% 1.37%

2013 5.56% 4.39% 1.17%

2014 6.09% 4.83% 1.26%

2015 6.33% 5.16% 1.17%

2016 6.16% 5.06% 1.10%

5

Less energy available each succeeding year from increasing impact of outage correlation

• Outages have been a significant factor in the 12Maximum Generation Emergencies since June 1, 2016

6


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Forced, Planned, and Maintenance Outages Affect Availability During the Summer

7

Less energy available each succeeding year from growth of reliance emergency-only resources like demand response

• The markets have varying levels of demand responsebut not all are emergency-only like MISO

https://ferc.gov/legal/staff-reports/2017/DR-AM-Report2017.pdf p.198

LMRs at MISO can have long notification times, summer only obligations and require an emergency declaration to access

0

2,000

4,000

6,000

8,000

10,000

12,000

Notification Time (mins) Obligation Meas. Method Type Emergency

LMR characteristics at MISO

Pre-Emergency

Emergency

Capacity-only

Metered

M&V

FSL

Annual

Summer

>240

121 to 240

61-120

31-60

0-30

9

>240 mins Summer Metered Capacity Emerg-ency Only


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Emergency procedures increasingly requiredto access certain resources needed

to mitigate unit availability issues

Emergency Operating Procedures guide operator actions when an event has the potential to, or actually does, negatively impact system reliability

Conservative System

Operations

Severe WeatherAlert

Hot WeatherAlert

Cold WeatherAlert

Geo-Magnetic

Disturbance Warning

Maximum GenerationEmergency Procedures

Tier I Emergency

PriceOffer Floor

Tier II Emergency Price Offer

Floor

10

14,00012,00010,0008,0006,0004,0002,000

06/1/2015 9/1/2015 12/1/2015 3/1/2016 6/1/2016 9/1/2016 12/1/2016 3/1/2017 6/1/2017 9/1/2017 12/1/2017 3/1/2018

12,000

10,000

8,000

6,000

4,000

2,000

0

11

6/1/2015 9/1/2015 12/1/2015 3/1/2016 6/1/2016 9/1/2016 12/1/2016 3/1/2017 6/1/2017 9/1/2017 12/1/2017 3/1/2018

NSI

Less energy available each succeeding year means increased reliance on intermittent or unscheduled resources

• These resources regularly vary from 2 to 12 GWsWind

Less scheduled energy available each succeeding year through growth of variable energy resources

• Significant growth is expected for solar and wind asillustrated by MISO’s generator interconnection queue

12


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For each topic MISO will evaluate the sufficiencyof its current tools and investigate solutions

Emergency Resources

Rule set Performance

Cleared volume

Procedures to access capacity

Timing to obtain output

Availability Management

Rule set Incentives

Performance

Off-peak management Expected summer peak

outages

Utility cash flowsState of Market recommendation

State and MISO roles

Resource Requirements

Reserve margin assumptions

Capacity accreditation PRA resource mix

Seasonal efficiencies and risks

Resource accreditation and incentives

Availabilitymanagementassumptions

Changing resource mix

13

Current Behaviors Areas to InvestigateDependencies and

ConsiderationsExisting LMR

contractsNon-summer offer

incentivesResource types

MISO is working to improve transparency and establish guiding principles in the three identified issue areas

14

MISO is interested in engaging stakeholdersin order to enhance outage coordination

Current year + 2 years:

Today: Maintenance Margin

Future: Economic scheduling or enhanced

probabilistic process informed by RAN

From 1 month to7 days out:

Today: Maintenance Margin

Future: New deterministic generator outage analysis

tool TARA

From 7 days to the operating day:

Newly enhanced Multi-Day FRAC process with

resource sufficiency alerts based on resource offers

and known outages

15

MISO’s Multi-tool process for different time horizons


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Next Steps

16

• Options Underway already•

•

•

Create and integrate RAN forecasts into operations

Enable timely access to emergency-only resources

Limited enhancements to Outage Coordination underway

• Assess need and options to ensure sufficient availableenergy from committed capacity to meet planning criteria

• Assess need for additional tools, processes or marketenhancements•

•

•

More tools or market options for outage coordination?

Changes to Emergency Only Resource qualifications, Product Types, Accreditation?

Other changes to ensure committed capacity availability?

Questions?

17

Contact information• Kevin Vannoy [email protected]

Appendix

18


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Maintenance MarginAccess and Overview

http://www.oatioasis.com/woa/docs/MISO/MISOdocs/Maintenance_Margin.html19

MISO’s public Maintenance Margin information Increased outages can challenge reliability outside the summer peak

‐20,000

‐10,000

0

10,000

20,000

30,000

40,000

50,000

1/1/2018 2/1/2018 3/1/2018 4/1/2018 5/1/2018 6/1/2018 7/1/2018 8/1/2018 9/1/2018 10/1/2018 11/1/2018 12/1/2018

MISO AvailableMargin

20

2018 Summer: 79% Chance of Initiating MaximumGeneration Emergency Step 2b or Higher

21


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Actual performance of LMR’sDuring January 2018 Events

1000

900

800

700

600

500

400

300

200

100

0HE 8 HE 9 HE 10 HE11 HE 20 HE21 HE 7 HE 8 HE 9 HE10

Requested Delivered

22

Excess Capacity following the annual Planning Resource Auction continues to decline

23


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SPPRTO:OperationalCharacteristics

DerekHawkinsSupervisorReal‐time&Current‐dayEngineering,SouthwestPowerPool

[email protected]

Derek Hawkins leads a team of Southwest Power Pool engineers providing 24x7 support to the reliable operations of the nation’s power grid. Their function is key to the success of SPP's Mission: Helping our members work together to keep the lights on… today and in the future. Derek fosters relationships built on trust and integrity as he helps coordinate the integration of emerging technologies into SPP’s strategy of reliable operations.

Prior to this position, Derek served nine years as a support engineer in SPP’s operations organization focused on situational awareness, post-event analysis, and stakeholder initiatives.

Derek is a licensed Professional Engineer and NERC-Certified System Operator. He holds a BS degree in electrical engineering from Arkansas Tech University. When he's not helping to keep the lights on, you'll find him with his wife at the ball park or chasing that next adventure with their kids.

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SPP-RTO: Operational CharacteristicsDerek Hawkins, Supervisor Real Time Support

May 23, 2018

2SouthwestPowerPool SPPorg southwest-power-pool

The SPP Footprint: Members in 14 States • Arkansas• Kansas• Iowa• Louisiana• Minnesota• Missouri• Montana• Nebraska• New Mexico• North Dakota• Oklahoma• South Dakota• Texas• Wyoming

3

Helping our

members work together to keep the lights on … today and in the future.

Our Mission


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4

North American Independent System Operators (ISO) and Regional Transmission Organizations (RTO)

Summer Peak: 50,622 MW

Winter Peak: 43,584 MW

Minimum Load: ~20,500 MW

Operating Region • Miles of service

territory:546,000

• Population served: 17.5M

• Generating Plants: 795

• Substations: 4,929

• Miles of transmission: 66,497

• 69 kV 16,862• 115 kV 15,684• 138 kV 9,703• 161 kV 5,615• 230 kV 7,523• 345 kV 11,016• 500kV 92

5

GENERATING Capacity* by Fuel Type(87,086 MW total)

6* Figures refer to nameplate capacity as of 1/1/18


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7

2017 Energy Production by Fuel Type (259,554 GWh total)

19.5%

46.3%

4.2%

22.7%

6.8% 0.6% 0.2%

Gas (19.5%)

Coal (46.3%)

Hydro (4.1%)

Wind (22.7%)

Nuclear (6.8%)

Other (0.3%)

Solar (0.2%)

8

9

Wind in SPP’s System• Wind installed today: 17,796 MW

• Maximum wind output: 15,690 MW (12/15/17)

• Wind Capacity MW (1/1/2018 – 5/8/2018) >14GW, 25 days

>14.5GW, 10 days

>15GW, 0 days

• Largest windfarm: 400 MW (Grand Prairie in Holt County, NE)

• Unbuilt wind w/signed interconnection agreements: ~10 GW

• Wind in all stages of study and development: ~60 GW

• Forecast wind installation in 2020: >20 GW (more than SPP’s current minimum load)


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561 2171 01146

3827 3328

1877

52567427 7427

857312400

1572817750

1775020326

25391

30456

1775018958

22300

30650

39010

2022

4805947190 45394 45302

45873

50622 50574 50622 50718 50958

51198

16560 1670617660 18092 17370

1994820417

20465

20561

2080121041

0

10000

20000

30000

40000

50000

60000

2011 2012 2013 2014 2015 2016 2017 2018 2020 2025 2030

Yearly Installed Capacity Total Installed Capacity Future Trend Based on 17-Year History

Future Trend Based on 9-Year History Forecasted End of the Year Installed Capacity SPP Annual Peak Load

SPP Annual Minimum Load

10

Wind Capacity Installed By Year

11

Wind Penetration

12

• Maximum wind penetration: Instantaneous: 63.96% (4/30/18) Hourly Average: 62.89% (4/29/2018) Daily Average: 54.1% (4/29/2018) Wind Penetration Highs (1/1/2018 – 5/8/2018) >60%, 6 days

>50%, 40days

• Average wind penetration (2017): ~25%

• Max wind swing in one day: >10 GW(12.5 GW to 2 GW back to 12 GW)

• Max 1-hour ramp: 3,700 MW


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13

Annual Average Wind Speeds

Wind, 60,770

Solar, 17,667

Natural Gas, 1,879

Steam Turbine, 29

Storage, 1,212Pending GI Requests

14

MW Requested by Generation Type

May 11, 2018

Solar in the U.S.

15

Solar in SPP


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16

Focus on renewable forecast accuracy

Offline and online VSAT

PMU siting on new generation

Flexible product evaluation

Planning process enhancements

Identify and monitor increased risk scenario contributors

Interchange Capabilities

17

2017 Congestion Patterns

18

Flowgate Name Region Flowgate Location

WDWFPLTATNOW Western Oklahoma

Woodward - FPL Switch 138 kV ftlo Tatonga - Northwest 345 kV (OGE)

NEORIVNEOBLC SE Kansas / SW Missouri

Neosho - Riverton 161 kV (WR-EDE) ftlo Neosho - Blackberry 345 kV (WR-AECI)

PLXSUNTOLYOA West Texas (Lubbock)

Plant X Sub - Sundown 230 kV ftlo Tolk - Yoakum 230 kV (SPS)

SHAHAYPOSKNO Western Kansas

South Hays - Hays 115 kV ftlo Post Rock - Knoll 230 kV (MIDW)

VINHAYPOSKNO Western Kansas

Vine - Hays 115 kV ftlo Post Rock -Knoll 230 kV (MIDW)

CARLPDLUBWOLWest Texas(Lubbock)

Carlisle - Doud 115 kV ftlo Lubbock South - Wolfforth 230 kV (SPS)

HANMUSAGEPEC Oklahoma City area

Hanncock - Muskogee 161 kV ftlo Agency - Pecan Creek 161 kV (OKGE)

SILSPRTONFLI NW ArkansasSiloam - Siloam Springs 161 kV ftlo Tonnece - Flint Creek 345 kV (CSWS-GRDA)

OSGCANBUSDEA TX Panhandle (Amarillo)

Osage Switch - Canyon East 115 kV ftlo Bushland - Deaf Smith 230 kV (SPS)

FRASPECOLMEAEastern SD /Nebraska Border

Ft. Randall - Spencer 115 kV (NPPD-WAUE) ftlo Meadow Grove - Kelly 230 kV (NPPD)


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19

Flowgate Name Region Flowgate Location

WDWFPLTATNOW Western Oklahoma

Woodward - FPL Switch 138 kV ftlo Tatonga - Northwest 345 kV (OGE)

NEORIVNEOBLC SE Kansas / SW Missouri

Neosho - Riverton 161 kV (WR-EDE) ftlo Neosho - Blackberry 345 kV (WR-AECI)

PLXSUNTOLYOA West Texas (Lubbock)

Plant X Sub - Sundown 230 kV ftlo Tolk - Yoakum 230 kV (SPS)

SHAHAYPOSKNO Western Kansas

South Hays - Hays 115 kV ftlo Post Rock - Knoll 230 kV (MIDW)

VINHAYPOSKNO Western Kansas

Vine - Hays 115 kV ftlo Post Rock -Knoll 230 kV (MIDW)

CARLPDLUBWOLWest Texas(Lubbock)

Carlisle - Doud 115 kV ftlo Lubbock South - Wolfforth 230 kV (SPS)

HANMUSAGEPEC Oklahoma City area

Hanncock - Muskogee 161 kV ftlo Agency - Pecan Creek 161 kV (OKGE)

SILSPRTONFLI NW ArkansasSiloam - Siloam Springs 161 kV ftlo Tonnece - Flint Creek 345 kV (CSWS-GRDA)

OSGCANBUSDEA TX Panhandle (Amarillo)

Osage Switch - Canyon East 115 kV ftlo Bushland - Deaf Smith 230 kV (SPS)

FRASPECOLMEAEastern SD /Nebraska Border

Ft. Randall - Spencer 115 kV (NPPD-WAUE) ftlo Meadow Grove - Kelly 230 kV (NPPD)

Coordinating Congestion Management

20https://www.nerc.com/pa/rrm/TLR/Pages/Reliability-Coordinators.aspx

Seams Coordination

21

Congestion Management Events (CME)

Transmission Loading Relief (TLR)

Reconfiguration

Operating Guides

Out-of-Merit Energy (OOME)

Market-to-Market (M2M)

• Utilize market resource dispatch to control loading

• May or may not be accompanied by a TLR

• SPP is also utilizing auto-activation for identified constraints


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22



Reconfiguration

Operating Guides



• May be used in conjunction with CME when appropriate conditions exist:• IDC curtailable transactions• NNL impacts• External impacts

• SPP also receives notifications when another RC issues a TLR that impacts transactions sinking in BAs under SPP RC purview

23



Reconfiguration

Operating Guides



• In certain instances, reconfiguration of the transmission system may result in decreased loading of constrained facilities

• These options are studied by operations planning and real-time engineers*

* SPP staffs two 24x7 engineers for real-time operations support

24



Reconfiguration

Operating Guides



• Sometimes, local area problems warrant actions outside of the Interconnection-wide relief procedures

• SPP helps to facilitate appropriate communication, coordination, and actions needed between affected entities


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25



Reconfiguration

Operating Guides



• Situations may arise where congestion is highly impacted by the output of non-dispatchable generation

• Operating instructions to maintain output at a certain level may be necessary

26



Reconfiguration

Operating Guides



• Only occurs between SPP and MISO• Initiated by either SPP or MISO• Achieve least cost re-dispatch needed

to provide the required physical relief on a flowgate

• Limited to Reciprocal Coordinated Flowgates (RCF)

27

M2M


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Priority Number One: RELIABILITY

28

Safe Operating Mode (SOM) may be initiated if none of the above options

result in satisfactory flow control or do not address other reliability concerns.

Thank You

Connect with SPP:

29

SouthwestPowerPool SPPorg southwest-power-pool


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HumanPerformanceandSkilledWorkforceJamesMerlo

VicePresidentofReliabilityandRiskManagement,NERC

[email protected]

James Merlo is a Vice President at NERC, leading the Reliability Risk Management department. Joining NERC in July 2011, James leads the electric reliability organization’s efforts to assess the industry status and needs with regard to events and occurrences on the Bulk Electric System and explores human performance challenges affecting bulk power system reliability. In this role, he identifies opportunities and methods for improvement based on proven methods from other industries and within the electrical industry to improve the reliability of the bulk power system. Additionally, he is responsible for ensuring that reliability based industry alerts, lessons learned, best practices and other valuable industry publications are quickly identified and communicated to the industry stakeholders and other various audiences.

James served in a variety of leadership roles in the United States Army including combat tours in Desert Storm and Operation Iraqi Freedom. Significant positions include; Deputy Brigade Commander in Baghdad, Iraq 2004-2005 and as an assistant professor and program director at the United States Military Academy.

James has his Bachelor of Science in Human Factors Psychology from West Point, his Masters in Engineering Psychology from the University of Illinois, and his PhD in Applied Experimental and Human Factors Psychology from the University of Central Florida. He is the author of over 50 publications and book chapters on the subjects of human factors engineering and human performance.

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Midwest Reliability Organization 2018 Spring Reliability ConferenceJames Merlo, PhDVP, Reliability Risk ManagementMay 23, 2018


2017: Impacts Must be Delineated

Wind Event vs. Water Event

Hurricane Ike ‐ 2008 Wind Hurricane Harvey – 2017 Water


Two Category 5 Events to Analyze

• Hurricane Harvey’s water flooded Houston and would not quit

• Hurricane Harvey’s winds hit South Texas

85 substations damaged

225 transmission line outages

Over 850 transmission line structures downed/damaged

Over 6000 distribution poles downed/damaged

• Hurricane Irma was the largest impact storm to ever hit Florida

A record 4.45 million customers out of service for Florida Power & Light

Previous record was 3.24 million during Hurricane Wilma in 2005

Irma restoration took only 10 days versus 18 days during Wilma

22018 MRO Spring Reliability Conference Conference

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• Drones hastened restoration following both Harvey and Irma with unexpected versatility

• Mutual Assistance agreements provided essential equipment and material for both Harvey and Irma restorations

• Florida and its utilities shortened Irma restoration time with strong, prior investment in system hardening

Event Analysis Key Findings & Recommendations


Events Analysis Process Capturing Faint Signals


Control Chart for the non-EMS Events (Per Month) Over Time


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Control Chart for the EMS Events (Per Month) Over Time


Cause Codes


Continued Decline in Average Transmission Outage Severity


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Correct Protection System Operations Rate


Misoperation Rates Continuing to Decline


Misoperation Rates Continuing to Decline


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200 kV+ Outages by Cause Code


BPS Transmission Related Events Resulting in Load Loss


BPS Transmission‐Related Events Resulting in Load Loss


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• Retirement/displacement of conventional generation Variable energy resources

Rapid penetration of electronically‐coupled resources

• Essential Reliability Services

Reduced inertia

Frequency Reponses

Voltage Support

Ramping and flexibility needs

• Rapid penetration of new loads

• System controls and protection coordination

• Modeling and simulation constraints

• Increasing interface with distribution‐centric resources

System Dynamic Character is Changing


Primary & Secondary Frequency Control


Human Error


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Duck Curve


The Need For Flexibility:A Future, Not a Scenario

Lo

ad

& N

et

Lo

ad

(M

W)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

28,000

30,000

32,000

34,000

Load, Wind & Solar Profiles --- Base ScenarioJanuary 2020

Net_Load Load Wind Total Solar

Win

d &

So

lar

(MW

)

6,700 MW in 3-hours

7,000 MW in 3-hours

12,700 MW in 3-hours

Net Load = Load - Wind - Solar


Work as Planned


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Work as Executed


Human Capital


All Trying to do the Right Thing


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Sometimes it is a Human


Your Artifacts Help Define You


Risk versus Consequences


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Blue Cut Fire Disturbance

• Event occurred on August 16, 2016 Not a qualified event

Entities volunteered to work with ERO

• Fire caused 13 500 kV line faults and two 287 kV line faults

• NERC/WECC ad hoc task force created to identify causes

• Published disturbance report in June 2017

• Key Findings: Use of momentary cessation

Frequency‐related tripping


Level 2 NERC Alert:Industry Recommendation

• Recommended actions: Mitigate erroneous frequency tripping

Recovery from momentary cessation

• Data collection to understand extent of condition


Clarification and Recommendation for Momentary Cessation


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Canyon 2 Fire Disturbance

• Event occurred on October 9, 2017 Not a qualified event

Entities volunteered to work with ERO

• NERC/WECC event analysis, NERC IRPTF technical support

• Published disturbance report in February 2018

• Key Findings: No frequency‐related tripping

Continued use of momentary cessation

Voltage‐related tripping


Canyon 2 Fire Disturbance Aggregate Solar PV Response

~15 minutes

‐682

‐74

‐1011

Fault 1:682 – 0 = 682 MW

Fault 2:1011 – 74 = 937 MW


• No erroneous frequency tripping Actions from first Level 2 Alert appear to have mitigated identified issue

By Canyon 2 Fire disturbance, 97% of manufacturer’s BPS‐connected fleet had been updated

• Continued use of momentary cessation

Most inverters use momentary cessation (V < 0.9 pu)

Recovery following momentary cessation varies, relatively slow for grid dynamics

Updated recommendation for momentary cessation – eliminate the greatest extent possible

• Transient overvoltage tripping and application of the PRC‐024‐2 ride‐through curve

Key Findings


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Key Finding: Application of Voltage Ride-Through

“May Trip Zone”

…NOT a “Must Trip Zone”

Curve is a minimum requirement, NOT design criteria.


Key Finding:Transient Overvoltage Tripping


Second Level 2 NERC Alert:Industry Recommendation

• Mitigating actions: Dynamic model improvements

Mitigation of momentary cessation

Plant control loop coordination

Mitigation of voltage‐related tripping

Information sharing among operating entities

• Planning and operations studies to ensure no potential stability risks

Response to Regional Entity of study findings by December 7, 2018


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Modeling Notification: Momentary Cessation

• Issue: Existing models largely DO NOT accurately represent installed resource performance

• Identified issue that needs to be addressed for models in planning and operations studies

• Developed notification to help industry in modeling efforts

• Guidance provided as part of second NERC Alert


• Disturbance analyses and reports Blue Cut Fire, Canyon 2 Fire, (and upcoming Angeles Forest) Disturbances

• Level 2 NERC Alerts

Identifying extent of condition, and recommending mitigating actions

• IRPTF Reliability Guideline Recommended BPS‐connected inverter‐based resource performance

• Modeling and simulations

Modeling Notifications

Leading interconnection‐wide stability studies to identify potential risks

• Industry education – webinars and workshops

• Outreach to BPS‐connected non‐BES resources (e.g., < 75 MVA)

• Reliance on SGIA, LGIA, and Facility Connection Requirements

Multi-Pronged Approach


Large BES Solar Resources

Operating PV> 75 MW

Illustration Purposes Only


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Operating PV> 1 MW

BPS-Connected Solar Resources

Illustration Purposes Only


Sub-cause Codes



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Wrap Up/Questions and Answers John Seidel

Senior Manager of Operations and Reliability, MRO

[email protected]

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Common Acronyms Reference Guide

BA Balancing Authority NERC North American Electric Reliability Corporation

BES Bulk Electric System PC Planning Coordinator

BESNet Web-based application used to submit Self Determinations and Exception Requests

RAI Reliability Assurance Initiative

CFR Coordinated Functional Registration RAM Risk Assessment & Mitigation

CIP Critical Infrastructure Protection RC Reliability Coordinator

CMEP Compliance Monitoring & Enforcement Program

RRA Region-wide Risk Assessment

DP Distribution Provider SA Situational Awareness

EA Event Analysis SDN Self Determination

EMS Energy Management System SDT Standard Drafting Team

ER Exception Request SME Subject Matter Expert

ERA Entity Risk Assessment SOL System Operating Limits

ERO Electric Reliability Organization SPS Special Protection System

GO Generator Owner SRI Severity Risk Index

GOP Generator Operator TO Transmission Owner

ICCP Intercompany Communications Protocol TOP Transmission Operator

IROL Interconnection Reliability Operating Limits

TP Transmission Planner

JRO Joint Registration Organization UFLS Underfrequency Load Shed

LSE Load Serving Entity UVLS Undervoltage Load Shed

MRO Midwest Reliability Organization

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