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Operating Committee MeetingPresentationsMarch 10-11, 2015 | Jacksonville, FL

*All presentations are posted with the written consent of the presenters.

1

Presentation 6.a.i

SPP Reliability Plan

NERC OC

March 10, 2015

Bruce [email protected] · 501.614.3214

2

mailto:[email protected]

Integrated System – PROJECT - MILESTONES Milestones

• SPP will take over RC function from MISO: 6/1/2015

• BA function will transition from WAUE to SPP: 10/1/2015

• Tariff and Interchange will transition from WAUE to SPP on: 10/1/2015

• SPP will take on TSP and PA function for IS System in West: 10/1/2015

• All Generation and Load currently balanced by WAUE BA Area will be participating in SPP Market: 10/1/2015

3

LOAD – GENERATION - TRANSMISSION

SPP/IS Integration

4

• Western Area Power Administration Upper Great Plains Region (BA, TOP, TO, GOP)

• Basin Electric Power Cooperative (TO, GOP, GO)

• Heartland Consumers Power District (HCPD) (TO)

• North Western Energy (NWE) (TO, GO, GOP)

• Missouri River Energy Services (MRES) (TO, GO, GOP)

• Corn Belt Power Cooperative (CBPC) (TOP, TO)

• Harlan Municipal Utilities (Load only)

• Minnkota Power Cooperative (Load only)

• Minnesota Municipal Power Agency (Load only)

• Southern Montana Generation and Transmission (Load only)

• Northern States Power (Load only)

• NIPCO (Load only)

• East River Electric Power Cooperative (Load only)

Overview of Entities With load, generation and/or facilities inside WAUE BA Area

5

Overview of Neighboring Entities“New” Neighboring TOPs and LBAs for SPP RC per 6/1/2015: • SPC Canada (Saskatchewan Power Corp.) – 1 new Tie Element

• WAPA-Upper Missouri West (DC Tie Miles City) – 1 new Tie Element

• WAPA-Lower Missouri (DC Tie Rapid City) – 1 new Tie Element

• WAPA-Lower Missouri (SGE – Stegal DC Tie) – 1 new Tie Element

• AECI: Associated Electric Cooperative, Inc – 1 new Tie Element

• OTP (Otter Tail Power Company, Minnesota, North Dakota South Dakota) – 31 new Tie Elements

• GRE (Great River Energy , Minnesota and Wisconsin) – 5 new Tie Elements

• MDU (Montana Dakota Utilities, Montana, South Dakota, North Dakota) – 74 new Tie Elements

• NSP (Northern State Power Company, Xcel Energy Wisconsin, Michigan, Minnesota, North Dakota South Dakota) – 13 new Tie Elements

• ALTW (Alliant Energy West, Iowa, Wisconsin, Minnesota) – 63 new Tie Elements

• DPC (Dairyland Power Cooperative, Wisconsin) – 1 new Tie Element

• MEC: Mid-American Energy Company – 88 new Tie Elements

6

EntityLoad

Peak (MW)Generation

Capacity (MW) Other

1 WAUE / UGP 2000-2500 Capacity inside WAUE 25006 Hydro plants in

Eastern Interconnect

2 BASIN 1300Own 3925, Operate 4913,

Capacity inside WAUE 2600

3 North Western Energy 350 Capacity inside WAUE 500

3 jointly ownedcoal plants:

Bigstone 111, Coyote 43, and Neal 200

4 Heartland (HCPD) 150 182

Shares of Whelan, Laramie, and

Wess Windfarm

5Missouri River EnergyServices (MRES) 300

580,Capacity inside

WAUE 450Share of Laramie, Exira, Watertown

6Cornbelt Power Cooperative(CBPC) 350 400

Shares of Neal (75)Wisdom, WSCC, etc

7 City of Harlan IOWA 12 12 Share of Louisa in MEC

8 Southern Montana (SME) 3 3Load will be registered

by UGPM

Total added to SPP ~4700 MW ~7700 MW

Entities with load and/or Generation inside WAUE BA Area

7

Capacity by Fuel Type

Fuel Type SPP Current Capacity IS

COAL 25261 2650

GAS 30404 1280

WIND 8600 910

NUKE 2555

OIL 1214 104

HYDRO 781 2467SUN 51

Other 20 125+150

TOTAL 68886 7681

8

• SPP footprint is growing by 11% (9,450 miles transmission)

• 5 DC Ties/Lines – Miles City 150-200 MW

– Rapid City 200 MW

– Stegall DC Tie 200 MW

– Coal Creek – Dickinson 1100 MW

– Square Butte – Arrowhead 550 MW

• Phase shifter with Canada (SASK)

• 3 Special Protection Systems (Miles City, Garrison, Fort Peck)

• 200+ AC tie-lines

• 40+ flowgates

• 18 Operating Guides

SPP Footprint Additions - Transmission

9

• 653 additional bus level loads (pnodes in commercial model)

• 327 additional substations (currently SPP has 187 substations modeled in WAUE BA) ~514 stations total

• 105+ additional resources (7600 MW)

• 15,000 – 20,000 number of ICCP points (real time data exchange)

• Switchable load between West and East (100 – 150 MW)

SPP Footprint Additions – Load/Generation

9

CURRENT SITUATION WAUE BAWEST EAST

10

New Terms and Situations

• Federal Service Exemption (FSE)

• Co-supplied Load (Basin, HCPD, MRES)

• Net Zero Interconnection Agreement (Groton – Day County 220 MW)

• Switchable Load and Generation Fort Peck. (100 MW Load, up to 3 hydro in West 3x40 MW)

• Phase shifter Saskatchewan Power Corp Canada. (200 MW)

12

SPP RC-to-RC Coordination Agreements

• SPP and Peak Reliability modifying current RC-to-RC Agreement, to be effective prior to June 1, 2015.

• SPP and Saskatchewan Power Corporation drafting Joint Operating Agreement to be effective prior to June 1, 2015.

13

Market Integration Overview• Effective 10/1/2015 all Generation and Load balanced

by WAUE BA Area will be participating in SPP Market and be part of the SPP BA.

• SPP Market Functions:

o Day Ahead Market

o Unit Commitment (Multi-Day, Day-Ahead, Intra-Day)

o Real Time Balancing Market (5 minute dispatch)

14

CERTIFICATION UPDATESPP – IS Integration

15

Certification Team Update• RC and BA Certification activities occurred over the last

2 months and will continue until SPP provides evidence for Bucket 2 items prior to June 1, 2015.

• SERC Certification Team in Little Rock, Arkansas at the SPP Campus on March 3, 2015.

• Weather issues led to a compressed on site meeting. Deliverables (Bucket List Items) will be provided to SPP by March 13, 2015.

• Additional meetings to be scheduled to discuss items.

16

Certification Team Update (cont’d)

• Positive high level findings to date– EMS Model Data Exchange between SPP and MISO

– Planning Model changes underway

• Items underway that need to be completed– EMS display updates to include the new area

– Completion of Operator training

– Completion of two RC-RC Agreements

– Completion and validation of the full EMS model

– Completion of SE and RTCA implementation of the IS facilities

17

Questions

18

Electric Information Network (EInet) Update

NERC Operating Committee MeetingMarch, 2015

Presentation 6.a.ii

Overview• EIDSN’s Mission• EInet Design• EInet Facts and Schedule• EInet 2015 Focus• Questions

Page 2

Mission

• Establish a network by which operational data (ICCP and synchrophasor) can be shared securely, consistently, and efficiently among the Eastern Interconnect Reliability Coordinators and other appropriate entities.

Page 3

Sprint Managed Network Services

GETVPNKey Server

Site #2Philadelphia, PA

Member Sites

DualCisco

Key Servers

Member Sites

GETVPNKey

Server Site#1New York,NY

Sprint - MPLS Network (Primary)

AT&T - MPLS Network (Backup)

DualCisco

Key Servers

EInet Design

EInet Facts and Schedule• 59 Circuits

– 24 Managed Ethernet– 35 T1 or NxT1

• Serving 21 entities– Eastern Interconnect RCs– Transmission Operators– Peak Reliability– ERCOT– NERC & SmartCloud

Page 5

EInet Facts and Schedule• Network Construction Schedule -

– Circuit installations began in January– Over 90% scheduled before mid-April

• Network Completion Goal – May• NERC target date for ‘turning off’ NERCnet –

June 30th

• Transition from Einet to NERCnet – Node owner’s decision

Page 6

2015 Focus

• Completion of EInet• Monitoring network stability and

management• Monitoring NERCnet to EInet transition• Establishing back-office operations and

administration• EIDSN Board to consider strategic direction in

September

Questions?

Rich MandesExecutive Director

[email protected]

EIDSN and DEWG• EIDSN’s 2015 focus on EInet operations and

support

• Adoption of DEWG functions would be EIDSN BOD decision– Not yet considered or discussed

• Key issue: How to incorporate non-member company representation

Page 9

NERC Event Analysis Subcommittee UpdateNERC Operating Committee MeetingMarch 10-11, 2015

Presentation 6.c

RELIABILITY | ACCOUNTABILITY2

• Four Lessons Learned released in 2015• EMSWG is preparing for EMS Conference Slatted for September 29-30 in Texas Theme will be SO confidence in tools

• Possible panel discussion with entities about 2015 winter system performance compared to the 2014 winter

NERC EAS Update


Revised NERC Event Analysis Process• EAS does not intend to alter the process• Minor revisions to help improve and clarify the intent of the EAP• Intro: Reinforced EOP-004 is a required standard, EAP is a

voluntary process and they have different purposes It would be a disservice to industry to for the event lists to be the same

• Process: Minor clarifying changes to help the end user grasp the high level process

NERC EAP Update


Categories: • Retired 1f (unplanned evacuation from a control center facility

for 30 minutes or more) • Retired 2b (complete loss of SCADA and monitoring capabilities

for 30 minutes or more)• Modified 2c to clarify that reporting is based on an event that

affects a number of facilities in a TOP’s footprint, it is not intended that a voltage excursion on one or two buses be analyzed

• Will not renumber to limit confusion

NERC EAP Update


• Appendix A was modified to clarify the timing requirements on the Brief Report and Event Analysis Report reports. The timing requirements of Brief Reports were also revised in response to industry requests. NERC’s mission is to improve the quality and completeness of reports and not burden the industry with short time requirements.

NERC EAP Update


NERC EAP Update

Appendix C was modified to clarify expectations • Added Item 1: NCR # Item 8: A list of relevant sustained forced outages and the bus

configuration is requested Item 11: Description of emergency actions taken (if required) Item 19: Corrective actions were included (if applicable) Do these changes

make Appendix C clearer?

NERC Lessons Learned Summary

NERC Operating Committee MeetingMarch 10-11, 2015

Presentation 6.c.i


• Four NERC lessons learned (LL) have been published to date in 2015 LL20150201 Digital Inputs to Protection Systems May Need to be

Desensitized to Prevent False Tripping Due to Transient Signals LL20150202 Consideration of the Effects of Mutual Coupling when Setting

Ground Instantaneous Overcurrent Elements LL20150301 Importance of Backup Energy Management System Failover

Testing after Network Device Reconfiguration LL20150302 Importance of State Estimator Save Cases and

Troubleshooting Guide

NERC Lessons Learned Published in 2015


• Converter station was lost due to erroneous initiation of a top-oil temperature trip signal from transformer protection system

• Operating entity investigated the connections in the transformer cabinet at the time and visually inspected the transformer and temperature gauges

• Both the transformer’s current temperature and the drag hand for the high-temperature indication were below alarm/trip levels

• No evidence of loose or corroded connections in cabinet• Multiple events initiated by this type of erroneous input signal

have been observed in the event analysis process

LL20150201 Digital Inputs to Protection Systems May Need to be Desensitized


• Entity identified transient signals were mistaken as a full-contact closure due to arcing or high-resistive bridging of the trip contact

• Protection digital inputs were too sensitive to transient signals, signal noise, or high-resistance contact bridging from outdoor mounted devices

• Determined (with vendor) that loading resistors should be installed on the digital inputs to desensitize them to transient signals

• Protection digital inputs should be designed/modified to reduce their sensitivity to a possible transient or high-resistance contact bridging being incorrectly detected as a full-contact closure

LL20150201 Digital Inputs to Protection Systems May Need to be Desensitized


• Event caused the unintended trip of multiple transmission lines and a large generation facility

• Trips were due to an incorrect setting on a numerical relay directional ground instantaneous overcurrent (IOC) element

• This setting caused it to misoperate in response to a fault on a mutually coupled adjacent line

• Failure to consider the effects of mutual coupling between adjacent lines led to the improper derivation of the ground IOC element settings, and this resulted in a protection system misoperation

LL20150202 Mutual Coupling when Setting Ground Instantaneous Overcurrent Elements



• When developing the ground IOC element setting, the entity did not consider nor simulate a line-end fault (with end open) on the adjacent line that was mutually coupled to the protected line

• The adjacent line ran in the same right of way as the protected line for a significant portion of the protected line’s length Line relays were placed in service with ground IOC settings that had the

potential to misoperate


• Entity disabled ground IOC and relied on directional ground distance elements since both elements were set to instantaneous trip for 80% of line

• Conducted a review of system to find similar issues • For applications where a zone 1 directional ground distance

element is not available, the entity has concluded that it is prudent to increase the ground IOC setting design margin applied to the worst-case out-of-zone fault to better account for protection system component tolerances and fault simulation modeling tolerances.



• Procedure/process need to give consideration of the effects of mutual coupling when setting ground IOC elements

• Lesson Learned discuss some item to consider in the out-of-zone fault simulations



• Performing maintenance on the primary control center’s (PCC) uninterruptable power supply (UPS), all functionality of the EMS system, including the communication circuits, were successfully transferred from the PCC to the alternate control center (ACC)

• After maintenance was complete EMS analysts attempted to bring system functionality back to the PCC but the attempt was unsuccessful

• Full system restart was then performed to establish system functionality at the PCC

LL20150301 Importance of Backup Energy Management System Failover Testing after

Network Device Reconfiguration


• PCC came on-line, but the ACC failed, and EMS analysts were unable to restore ACC functionality

• EMS functionality was lost due to communication circuits still connected to the failed ACC

• It should be noted that an EMS loss-of-functionality event will occur every time a full system restart is performed, and the duration of a typical event is five to eight minutes.

• Loss of EMS/SCADA functionality for 49 minutes during a scheduled transfer of the EMS from the alternate control center (ACC) to the primary control center (PCC)




• Upon subsequent investigation, it was discovered that due to a recent and extensive network device reconfiguration, one of the parameters was in error, and this resulted in the inability to restore ACC functionality via a full system restart

• Device configuration modifications were then performed, and the ACC was successfully restarted with functionality restored




Lessons Learned• EMS maintenance and reconfiguration operations should be

closely coordinated with vendors that are needed to support the changes to ensure that there are no overlaps in planned maintenance schedules

• Succinct and accurate communication between registered entities and vendors is essential to ensure that both parties fully understand their roles and obligations during planned maintenance operations

• Procedures for EMS system restart operations should be rigorously documented to ensure that the EMS can be restarted in the most rapid and secure manner

• Step-by-step checklist for the procedure is desirable to ensure that no steps are overlooked




Lesson Learned Cont.• Entities should periodically review EMS redundancy to ensure

ongoing independence between sites, including full functional failover testing.

• Entities should review and identify the extent of testing to be performed following significant EMS infrastructure reconfiguration.




• State estimator (SE) failed to solve for 37 minutes, resulting in real-time contingency analysis (CA)also being unavailable

• During this event, operators had system visibility via SCADA and could still take control actions, including the ability to shed load

• Inter-Control Center Communications Protocol (ICCP) continued to function, providing real-time data to the RC and the other local entities in the RC’s footprint

• Entity confirmed with its RC that the RC’s SE and provide real-time CA

LL20150302 Importance of State Estimator save Cases and Troubleshooting Guide


Lessons Learned• A SE should be able to automatically and frequently save cases

to assist in post-event analysis. It should also automatically save non convergent cases

• Operators and support staff should have clear guidance and training on troubleshooting state estimator failures. An online state estimator guide for systems operators should be available to ensure consistent troubleshooting. Periodic refresher training should also be employed, including reviews of recent aborted cases.

• A joint review of state estimator issues with other entities should be periodically conducted to ensure applicable common solutions are implemented.

LL20150302 Importance of State Estimator save Cases and Troubleshooting


• Directions to Lessons Learned:• Go to www.NERC.com > “Program Areas & Departments” tab >

“Reliability Risk Management” (left side menu) > “Event Analysis” (left side menu) > “Lessons Learned” (left side menu)

NERC’s goal with publishing lessons learned is to provide industry with technical and understandable information that assists them with maintaining the reliability of the bulk power system. NERC requests that industry provide input on lessons learned by taking the short survey. The survey link is provided on each Lesson Learned.

Link to Lessons Learned

Essential Reliability Services Status UpdateOperating Committee MeetingMarch 10-11, 2015

Presentation 8.b


ERSTF Activities

• Meeting held in Atlanta following last Operating Committee (OC) and Planning Committee (PC) Meetings

• Working meeting February 2015 in Dallas, TX• ERSTF Measures Framework Report posted online: http://www.nerc.com/comm/Other/Pages/Essential-Reliability-Services-

Task-Force-(ERSTF).aspx

• Pilot conducted for four measures endorsed by OC and PC in December 2014.

• Continued analysis on the remaining measures.

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


ERSTF Activities continued

• ERSTF presentation at the NERC Board of Trustees (Board) and Member Representatives Committee (MRC) Meetings Tom Burgess presented update to Board Supportive comments from all NERC segments of the MRC and Board Board approved the direction of the Task Force and moving forward as

currently identified

• CAISO executive articulated various concerns on their observations to date Reiterated “Duck Curve”

• Positive endorsement of actions to date Look to improve on communications by simplifying the message and

making it less technical to policymakers (but keep the technical language for justification)


Update on ERSTF Measures

• Data requests sent to nine entities for evaluating the four endorsed measures (entities volunteered)

• Entities submitted historical, present and forecasted data. The results were evaluated by sub-groups for submitted entities Measures 1, 2 & 3 (SIR and Freq Deviation)- Declining trend in inertia was

observed in a few areas, such as ERCOT, ISO-NE, MISO, and IESO. However, other areas had no significant changes or trends to date. Interconnect level measure still a challenge.

Measure 6 (Net Demand Ramping Variability) - Entities reported issues they uncovered while performing the analysis. It appears this measure is warranted to monitor for emerging load profile changes (Distribution Resource Impacts)


Update on ERSTF Measures, Cont’d

Frequency Subgroup Measures • Measure 4: Frequency Nadir at minimum SIR Conditions The subgroup continues to evaluate this measure

• Measure 5: Real-Time Inertial Model Task Force determined this would not be a ERSTF Measure, rather will be

finalized as a ‘good practice’ recommendation. Specifications for an example of an approach to calculate real time inertia will be provided. MISO and ERCOT have implemented this.


Update on ERSTF Measures, Cont’d

Voltage Subgroup Measures • Measure 7: Reactive Capability on the System The Subgroup is seeking endorsement from OC and PC on this measure and

is prepared to request data and perform data analysis

• Measure 8: Voltage Performance on the System This measure was ultimately retired and replaced with a specific measure

(Measure 10) targeting the potential impact of changing resource mix on grid/system strength (Short Circuit Ratio)

• Measure 9: Overall System Reactive Performance The subgroup continues to evaluate this measure

• NEW - Measure 10: Measure and evaluate Short Circuit Ratio with FIDVR type Response


Today- Endorsement from OC and PC

• OC and PC endorsement on Measure 7, and continued analysis of the remaining measures through data gathering and analysis

• Measure 7: Reactive Capability on the System This measure tracks the rotating and non-rotating dynamic reactive

capability per total megawatt load on the system (BA Level) for various areas at critical load levels (i.e. peak, shoulder and light load).

With the changing resource mix on the system, may see emerging scenarios or operating periods where reactive support may not be sufficient (lead and/or lag)

Task Force/Sub-Group has developed a template/spreadsheet for data gathering and analysis


Next Steps

• Next steps for the task force: Establish efficient data collection and analyze Measure 7 and possibly 4, 9,

& 10 (lessons learned from first request) Continue to develop Framework Measures Report Version 2 and capture

latest Task Force analysis (Measures, 1, 2, 3 and 6) and other decisions (Measure 5, 8 and 10).

Commence draft for Final Report (June 2015) on Measures and Methodology

Performance Analysis Subcommittee UpdatePlanning Committee MeetingOperating Committee MeetingMarch 2015

Presentation 8.c


• 2015 State of Reliability schedule• Metric review M-16 Element Availability Percentage CP-1 (Proposed Compliance Metric) Serious Risk Violations CP-2 (Proposed Compliance Metric) Potential Violations with Observable

Reliability Impact

• Discussion of Compliance Metric White Paper and reviewers’ comments

Overview


• Work is in progress!!!• Key Dates you need to know: Draft due to PC/OC reviewers on April 8 Comments needed back by April 15 Present to NERC OC and PC – April 21, 2015 Send to NERC BOD for acceptance – April 22, 2015

• Request: The PAS needs OC and PC reviewers

2015 SOR Schedule


• Changes proposed to Metric Description: Part A: Availability (APC) – Overall percent of Bulk Electric System AC

Transmission Elements operated at 200kV or above that is available for service as influenced by outage durations from both Automatic and non-Automatic events. Momentary outages are not considered in this metric.

Part B: Unavailability (This metric also includes the overall percent of Bulk Electric System AC Transmission Elements operated at 200kV or above that is unavailable for service (i.e. out of service) due to Sustained Automatic and Non-Automatic Outages. These outages will be broken down in Automatic (sustained) and Non-Automatic (operational) outages. Momentary outages are not considered in this metric.

M-16 Recommendations

Note: Alignment to reliability characteristic doesn’t seem beneficial (which was provided using an ALR designation). Therefore metrics will be referred to by a simple number. Document references are being updated to reflect this change.


• Not addressed in December 2014 because it is also dependent upon the outcome of the TADSWG planned outage data collection issue.

• Why does this one only include 200kV and above? The metric includes automatic outages and operational outages. Operational outages only exist for 200kV and above.

• PAS requests endorsement of the changes to this metric.

M-16 Recommendations


Compliance Metrics Team Members


CP-1 Proposal (Risk Focus)

• Definition: ALR CP-1 is a quarterly count of newly reported potential violations initially determined by compliance enforcement staff at the regions to be a Serious or likely Serious Risk Violation Risk as assessed by Enforcement staff Some minor adjustments expected as PVs progress through enforcement Data can also drive improvements to enforcement process (consistency

and development of Risk Elements)

• “Top 10” Requirements associated with Serious Risk Violations provide added value Information sharing on underlying causes and mitigation activities One logical focus area for development and evaluation of requirement-

level internal controls


Serious Risk Violations by Quarter


CP-1 Proposal

Figure 2 Standards and Requirements with Most Occurrences of Serious Risk Violations


ALR CP-2 (Impact Focus)

• Definition: ALR CP-2 is a quarterly count of the number of newly reported Compliance Exceptions or Potential Violations by Impact Tier level

• Should enable risk reduction using approaches proven in other industries and fields of study Industrial safety Quality control and process improvement

• Some adjustment occurs as PVs progress through enforcement • “Top Requirements” associated with observed impacts provide

added reliability risk-reduction value Information sharing on underlying causes and mitigation activities Another starting point for development and evaluation of requirement-

level internal controls


CP-2 Proposal

System Events

Moderate Impact

Minor Impact

No Impact PVs

• Quarterly count of newly reported compliance violations and tier that represents the impact to BES (by requirement): Tier 3. Caused or contributed to a system event Tier 2. Impact beyond an objective threshold Tier 1. Some identified impact Tier 0. Nothing observed

• This would only require capturing one additional piece of information per potential violation or log

• This would provide objective data to track tends and make informed decisions to improve risk-based processes


ALR CP-2 Data Collection

Find and Fix these

To reduce the #and magnitude of these


CP-2 Proposal

Figure 1 CP-2 Trend


• Introduced these concepts at December 2014 OC and PC meetings.

• At that time, white paper wasn’t yet finalized, but the OC and PC did provide reviewers.

• January 30th there was a conference call and ReadyTalk to review the white paper with the reviewers

Compliance Metric White Paper

Jerry Rust Herb SchrayshuenDale Burmester Andrew TudorHassan Hamdar Doug PeterchuckJeff Harrison Paul Kure


• We received excellent feedback – in both quality and quantity• We addressed the comments received and incorporated their

feedback into the final Compliance Metric White Paper, included in the agenda packet.

• We are requesting endorsement of the Compliance Metric White Paper concepts and the recommendations made in it.

Compliance Metric White Paper


• NERC and the Regions• Move forward with ALR CP-1 and ALR CP-2 NERC and Regions establish the data stream in PVs and logs Work with NERC CCC and PAS (with input from OC and PC) to refine the

symptoms that qualify as “impacts” Create quarterly trends of ALR CP-1 and ALR CP-2 from 2012 to present as

the starting point “Mine” 2012 to present PV data to create “Top 10” High Impact and “Top

10” Serious Risk Requirements

• To the extent there are differences in logging approaches among Regions, include common elements to capture the necessary data to enable ALR CP-2

Recommendations from the Compliance Metrics White Paper (1 of 4)


• Share “common cause” information for impactful and Serious Risk violations as well as root cause information on violations that caused or contributed to system events

• Use the ALR CP-1 and ALR CP-2 metrics as input to the CMEP’s Risk Elements and Focus Areas

• Visibility of metrics once created



• NERC and Regions periodically review differences among Regions’ Serious Risk violations as an input to developing Risk Elements, identifying Regional specific risks, as well as increasing consistency in the risk assessment process

• Use ALR CP-1 and CP-2 and other currently collected compliance data to create a summary dashboard that gives an overview of the state and trend of BES risk due to compliance violations Registered Entity compliance maturity Compliance focus on materiality



• Registered Entities• Consider the “Top 10” lists as a starting point for the

development of internal controls • Pursue logging authority and aggressively self-inspect and self-

correct• Capture underlying causes and actions taken to correct

compliance exceptions• For new compliance self-reports and log entries, include an

assessment of impact of the non-compliance by level and describe the impact observed


NERC Operating Committee Strategic Plan 2015 - 2019

Alan BernNERC Operating Committee MeetingMarch 10, 2015

Presentation 8.d


• Five year outlook aligned with ERO Strategic Plan James Merlo – Goals 3, 4 and 5 Coordinated with RISC priorities

• Review Team – Alan Bern, Jerry Rust and Todd Lucas• Two part review of NERC Operating Committee (OC) Strategic

Plan Overview of draft NERC OC Strategic Plan Assign OC members to OC Goals review teamso Four Strategic Plan OC Goals

– OC 1 – Jerry Rust– OC2 – Todd Lucas– OC3 – Don Watkins– OC4 – Alan Bern

Note: Looking for input on additions and improvements, not grammar

Strategic Plan Update


Introduction

No Change f


Purpose


OC Goal 1

No change


OC Goal 2

No change

No change


OC Goal 3


OC Goal 4


• Break into four groups for 30 minutes Review assigned goal and associated action plans. Identify any missing components in action plans and recommend

modifications.

• Jerry, Todd, Don and Alan will gather input and update plan as needed on Tuesday night

• Alan will send updates to Jim Case and Jim Castle on Tuesday night

• NERC OC will vote on 2015 – 2019 Strategic Plan on Wednesday

Review Teams

Generating Unit Operations During Complete Loss of Communications Peter BrandienNERC Operating CommitteeMarch 10, 2015

Presentation 8.e


• Peter Brandien• Ken McIntyre• Jerry Mosier• Pierre Paquet

Working Group Members


• AEP• City of Austin• Black Hills Corporation• DTE Electric• Duke Energy• Idaho Power Co• Indiana Municipal Power Agency• Manitoba Hydro• Madison Gas & Electric Co• North American Generator Forum• NPCC Task Force on Coordination

of Operation

Entities that Provided Comments

• Occidental Energy Venture, LLC• Peak Reliability• Louisville Gas and Electric

Company and Kentucky Utilities Company

• Public Service Enterprise Group• Southwest Power Pool• Virginia State Corporation

Commission• Wisconsin Electric Power Co.


Overview of Industry Comments

• Half of the Comments were grammatical improvements• Few comments that the Guideline wasn’t detailed enough Particularly in the area of training or what guidance should be provided by

the RC, TOP and BA Should cross reference NERC Reliability Standards

• Two comments about “Local” Balancing Authority confusing for MISO participants Changed “Local” to “Applicable”


Overview of Industry Comments, cont.

• Concern that Guideline conflicts with NERC Reliability Standards PRC-024, Generator Frequency and Voltage Protective Relay Settingso Gen trip points

EOP-002-3.1, Capacity and Energy Emergencieso R5 …..only use the assistance provided… …..interconnection’s frequency bias….

General concern about transmission security issues due to generators taking unilateral action

ERO Enterprise Reporting and Data Warehouse Strategic Vision

James Merlo, Senior Director Reliability Risk ManagementOperating Committee MeetingMarch 2015

Presentation 8.g


Core Focus for 2015

• Master Data Inventory - beginning• Line of Business Inventory - beginning• Data Definitions and Standards• Data Conformation and Integrity Assurance• Data Collection Improvements• Master Data Model


Questions and Concerns

• Kinds of Data – Historical, KPI, task-specific, others• Data integrity – assurance of data accuracy• Data applicability – the right data to answer the right questions• Data complexity – data relationships and models• Data standards – can data be matched from different sources

(American Electric Power)


Problem Statement

• Legacy Application Architecture led to Vertical Data Silos. Therefore the data: is difficult to access is difficult to integrate across the enterprise is of limited enterprise analytical value


• Know our data• Decouple data from applications• Enable ERO Enterprise data consumption Ad-hoc reporting Analytics Data sharing Historical trending

Solution


NERC Data Configuration – Current State

OATIUser Portal

TADS (including Misops)

DADS

SED

GADS

Functional Entities

Designated Reporting Entities

State of Reliability Report

ALR Metrics

SRI

Critical Infrastructure

strategic roadmap & Grid resilience

Input to LTRA

Dashboards on website

Data scrub

pcGAR Entity BenchmarkingNon-Reliability data

Manual Data Collection (Excel spreadsheets)

Regional Entities

ALR 6-1Transmission Constraint Mitigation

ALR 2-3Underfrequency Load Shedding

ALR4-1Misoperation Rate

Various Functional Entities

ALR 3-5IRO/SOL data

ALR 1-5System Voltage

NERC Internal data collection

ALR 2-4% recovery DCS

ALR 2-5MSSC DCS

ALR 1-12Interconnection Frequency Response

ALR 6-2 & 6-3EEA Levels 1-3

ALR1-3Planning Reserve Margin

LTRA

ALR1-4Transmission Related load loss events

OE-417 & EA Report

ALR Metrics/ Reliability Indicator Dashboard

TEAMS

CRATSRegional Entities OE-417/EOP-004

Regional Entities(Spreadsheet)Assessment Areas LTRA/Seasonal

AssessmentsRA DatabaseData scrub

ES&D


Roadmap / Vision

Phase II Phase III Phase IV Phase V …

Master Data Performance & Assessment Data Compliance Data Events Analysis Data

Ove

rsig

htDi

scov

ery

Inve

ntor

y an

d Co

ntro

lAn

alyt

ics

Plat

form

Master Data Inventory

Engagement Definition

Establish NERC data inventory working group and provide program continuity

Master Data Model

Distribution and Consumption (including self service)

Line of Business Inventory

Requirements -Compliance

ETL Framework

Line of Business Data Modeling

Enterprise Model Extension

Data Definitions and Standards

Data Conformation and Integrity Assurance

Extraction, Transformation and Loading

Requirements – Performance & Assessment

Requirements –Events Analysis

Disaster Recovery Framework

Data Collection Improvements

Overall Architecture

2014 FRAA ReportCritique, Data Problems, and Solutions

Robert W. CummingsDirector, Reliability Initiatives and System AnalysisOperating CommitteeMarch 10-11, 2015

Presentation 8.h


• June 1 – Begin analysis of events Gather and analyze 1-second and sub-second data for all BAL-003 and

ALR 1-12 frequency events

• July FWG/RS Meeting – present IFRO calculation results and • August 1 – Begin analysis of FERC For 714 NEL and generation

data• Mid-August – FWG & RS acceptance by conference call vote• September OC meeting – Present for approval• October 1 – File FRAA report with FERC• November 1 – Disseminate BA FROs

Original FRAA Schedule


Three outlier events in 2013 were evident for the Eastern Interconnection in 2014 SOR report• Several ALR1-12 events should NOT have been included in 2013• 19 events were eliminated – a did not meet selection criteria Inconsistent selection criteria – confusion with BAL-003 event criteria• ALR1-12 event selection criteria skews the statistical analysis• Corrupts correlation analysis being performed for SOR

Frequency Event Problems Found


1. Data skews found between 1-second and sub-second data starting in July 2013• 1-second event start times 18 to 22 seconds before sub-second

data – simply cannot happen• 1-second data is created by averaging sub-second sources • Found sign error in averaging software• Recalculated all 1-second data from July 2013 through 20142. Spurious step changes in 1-second frequency data found not related to system frequency events – started in July 2013• Found while applying drop-out/spike filters• Caused by switching data sources on the fly• Fixed when recalculating 1-second data

Frequency Data Problems Found


3. Frequency statistical analysis showed frequency variability an order of magnitude or more out of range (FRAA Table 5)• Exhibited in Western, ERCOT, and Québec Interconnections• The same problem went unnoticed in the 2013 FRAA report• Problem did not exist in 2012 FRI report• Analysis determined error started when 2012 frequency data

was introduced into the 3-year rolling dataset• 2012 and 2013 data had several thousand seconds of

frequencies as low as 56 Hz• Traced to lack of elimination of bad data from data used in

creating the average 1-second data• Stop-gap fix for 2014 FRAA report – need to fix root of problem



4. Stop-gap fix – 3-year dataset:• Western Interconnection cutoff – 59.5 Hz 287,262 seconds of data removed 91,232,854 seconds remaining

• ERCOT Interconnection cutoff – 59.5 Hz 368,638 seconds of data removed 88,538,959 seconds remaining

• Québec Interconnection cutoff – 58.5 Hz 431,239 seconds of data removed 86,770,408 seconds remaining

• Errors still may be imbedded in rest of data• Revisions did NOT change any IFROs 1 millisecond change in Québec Starting Frequency



Revisions to Table 5


Proposed Solutions

• ALR 1-12 event selection – review and revise event selection criteria to eliminate skewing of data Recommended in 2014 FRAA report

• Recalculate 2012 through 2014 1-second data with bad data detection algorithm at raw-data level before averaging

• Impose bad data detection algorithm at raw-data level before calculating 1-second data

• Impose noise/spike detection filters in 1-second data stream• Monthly processing of 1-second data and weekly review of

frequency event candidates for both ALR 1-12 and BAL-003-1


• Create a dependable, commercial grade data source and frequency data calculation to ensure quality of data

• Raw data sources should be streamed to NERC or a class A calculation center to ensure control over data sources

• Select PMU data should be used for this purpose (voltage and angle) so that NERC can calculate the frequency on a uniform basis – different devices calculate frequency differently (a lesson from the 2003 blackout)

Long-term Solutions on Frequency Data

Eastern InterconnectionFrequency InitiativeTroy BlalockSouth Carolina Electric and GasNERC Resources Subcommittee Vice ChairmanNERC Operating Committee MeetingMarch 10-11, 2015

Presentation 8.i


In less than three months time……

NERC Advisory was developed, reviewed and approved. Advisory issued on February 5, 2015.

NERC Advisory


Meetings have been held with:

Discussion with OEM’s


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

What has been learned

Graphic from GE info bulletin PSIB20150212


No Frequency Algorithm in DCS

Frequency Algorithm in DCS

175 MW GE7FA Gas GE Mark VI Turbine

3/3/2015

Tale of Two Tales


What we learned

2) In regards to factory dead bands and droop settings:Gas Turbines 15mHz and 4%

MST and LST 120 – 252 mHz and 5%

Turbines 50 mHz and 60 mHz V machines and 5%

Turbines 50 mHz and 2-8%

Turbines 50 mHz and 5%

SteamTurbines 36 mHz and 5%


Proportional Response vs. Step Response

More complex issue…. Almost every OEM does it differently. For some this is complicated to modify.

What we learned


Steps OEM have taken

Technical communications to the fleet


• Factory Setting vs. modifications made by GO or Architect/ Engineering Firm

• Speed Controller – How accurate can it read in % speed• Architect/ Engineer Firms designs ex. Black & Veatch, Fluor

Daniel• Markets/ ISO penalizing frequency response vs. base point

deviations• Cost for changes are relatively small but still a cost. GO’s in the

ISO have asked how will they be compensated.

Issues


OEM, NERC and NERC RS members April 6 1:30 to 3:30 PM and April 7 3:30 to 5:00 PM.

Upcoming Webinar

1

WWSIS - 3: Western Frequency Response and Transient Stability Study

GE Energy Nicholas W. Miller (PM)

Miaolei Shao Slobodan Pajic Rob D’Aquila

NREL Kara Clark (PM)

NERC OC/PC Briefing Jacksonville, FL

March 10-12, 2015

The final report has been released by DOE

Presentation 8.j

Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE

Team….

Who:

– Project Co-funded by DOE Wind and Solar Programs

– Project Management by NREL: Kara Clark

– Subcontract to GE Energy Consulting

Technical Review Committee:

• North American Electric

Reliability Corporation

• PacifiCorp • Public Service of New

Mexico

• Western Area Power

Administration

• Tucson Electric Power

• Western Electricity Coordinating Council

• California ISO

• Xcel Energy

• Sacramento Municipal

Utility District

• Arizona Public Service • Bonneville Power

Administration

• Western Governors

Association

• Electric Reliability

Council of Texas • Utility Variable-

Generation Interest

Group

• DOE

• Electric Power Research

Institute • Sandia NL

• Lawrence Berkeley NL

• Iowa State University

• University College

Dublin

• Arizona State University

2


Key Points

What: Stability – for the 1st minute after a big disturbance – is critically important limitation in the West

Why: Widespread worry that lots of wind and solar, especially combined with lots of coal retirements will irreparably disrupt grid stability.

In the context of ERSTF: will essential reliability services be affected (i.e. depleted, altered, enhanced...)

What we learned: The Western Interconnection can be made to work well with both high wind and solar and substantial coal displacement, using good, established planning & engineering practice and commercially available technologies.

3


WECC-Wide Summary(1)

Light Spring Base

(2)

Light Spring High Mix

Light Spring Extreme Sensitivity

Wind (GW) 20.9 27.2 32.6

Utility-Scale PV (GW) 3.9 10.2 13.5

CSP (GW) 0.9 8.4 8.3

Distributed PV (GW) 0 7.0 10.4

Total (GW) = 25.7 52.8 64.8

Penetration(3)

(%) = 21% 44% 53%

Wind 4.4

PV 3.7CSP 0.9DG 0.0

Others 19.9

Wind 8.4 PV 0.0

CSP 0.0

DG 0.0

Others 14.6

Wind 2.5PV 0.0CSP 0.0

DG 0.0Others 12.3

Wind 4.0 PV 0.2CSP 0.0DG 0.0

Others 24.9

Production/Dispatch in GW

Wind 4.7

PV 5.8CSP 1.5

DG 3.7

Others 15.1

Wind 8.4

PV 0.3CSP 0.0DG 0.2

Others 11.7

Wind 5.3

PV 0.8CSP 0.0DG 0.4

Others 5.5

Wind 6.9

PV 3.3

CSP 7.0DG 2.6

Others 11.4


Light Spring Load Study Scenarios Base Case High Mix Case

(1) Western Electricity Coordinating Council includes parts of Canada and Mexico, (2) Provided by WECC, (3) Penetration is % of total generation for this snapshot. 4


Frequency Response Analysis

5


Frequency Response with High Renewables

Interconnection frequency response > 840 MW/0.1Hz threshold in all cases. No under-frequency load shedding (UFLS).

Disturbance: Trip 2 Palo Verde units (~2,750MW)

3

2

Light Spring Base


Light Spring Extreme

2 3

1

1

~40GW increase in wind and solar, from ~21% to ~53%, caused initial ROCOF to increase ~18%. Nadir occurs ~20% sooner.

6


Wind Plant Frequency Responsive Controls

• Inertial control responds – to frequency drops only

– in 5-10 second time frame – uses inertial energy from rotating wind turbine to supply power to

system

– requires energy recovery from system to return wind turbines to nominal speed

– more responsive at higher wind speeds

– ERSTF: this is Fast Frequency Response, NOT System Inertial Response

• Governor control responds – to both frequency drops and increases

– in 5-60 second time frame

– requires curtailment to be able to increase power

– ERSTF: this is either Fast Frequency Response, or Primary Frequency Response (depending on aggressiveness of the control)

7


Frequency Control on Wind Plants

Light Spring High Mix Light Spring High Mix with governor control* Light Spring High Mix with inertial control* Light Spring High Mix with both controls


40% of wind plants (i.e., new ones) had these controls, for a total of 300 MW initial curtailment out of 27GW production.

1

2

3

4

1

2

3 4

8


Fault Ride Through Needed with High Levels of DG

Pessimistic

Pessimistic approximation to worst case 1547 under-voltage tripping (88%, no delay) Pacific DC Intertie trips Widespread, common mode tripping of DG (i.e. distributed solar PV results in system collapse

DG with LVRT DG without LVRT

Disturbance: Trip Pacific DC Intertie

1

2

1

2

9


Frequency Response Conclusions

For the conditions studied, system-wide frequency response can be maintained with high levels of wind and solar generation with both traditional and non-traditional approaches.

Traditional transmission system reinforcements to address local stability,

voltage, and thermal problems include: • Transformers • Shunt capacitors, (dynamic reactive support) • Local lines

Traditional approaches to meeting frequency response obligations are to commit synchronous generators with governors and to provide all response within an individual balancing authority area

Non-traditional approaches are also effective at improving frequency response including:

• Sharing frequency response resources • Frequency-responsive controls on inverter-based resources

• Wind • Utility-scale PV • CSP • Energy storage, (demand response)

There are caveats in report

10


Transient Stability Analysis

11


Heavy Power Transfer Affects Response More than High Wind and Solar

Disturbance: Trip Pacific DC Intertie… NO RAS enabled

Heavy summer Base Heavy summer Base with high COI flows Heavy summer High Mix with high COI flows

High power transfer drives performance in both Base case and High Renewables case.

1

2

3

2

3

1

California Oregon Interface Power Flow (MW)

4,800 MW

12


Transient Stability in Northeastern WECC

L

Aeolus

500kV

Large Coal Plants

13


0

5000

10000

15000

20000

25000

30000

35000

LSP Base LSP HiMix LSPHiMixXtrm

LSP Base LSP HiMix LSPHiMixXtrm

DSW NorthEast

WIND

Steam

PV

PSH

Other

NUC

HYDRO

GEO

GasCT

CSP

Coal

CCPP

Bio

Light Spring

Base

Coal Displacement in Light Spring Scenarios G

en

era

tio

n p

rod

uc

tio

n (G

W)

PV=photo voltaic, PSH=pumped storage hydro, NUC =nuclear, GEO=geothermal, GasCT=gas fired combustion turbine, CSP=concentrating solar power, CCPP=combined cycle power plant, Bio=biomass

Light

Spring

High Mix

Light

Spring Extreme

Sensitivity

Desert Southwest

Light

Spring

Base

Light Spring

Extreme

Sensitivity

Light

Spring High Mix

Northeast (of the West)

Co

al

Co

al

14


System Non-Synchronous Penetration (SNSP)

• Percent of non-synchronous generation (i.e.,

inverter-based generation like wind and solar)

compared to synchronous generation in a system • EirGrid (Irish grid operator) presently has 50% cap

on the amount of non-synchronous generation

allowed at any time

• ERSTF: a SNSP cap is similar to a SIM, but reflects

restrictions on short-circuit strength as well as

inertia

15


Synchronous vs. Non-synchronous

OK

Fail

Inverter-based MVA

Synchronous MVA

80% drop in Coal Dispatch. This

case passes Aeolus fault test.

90% drop in Coal Dispatch. This case

needs further reinforcement

Ge

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California Desert Southwest Northeast Northwest

Lig

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16


Dave Johnson Voltage

Light Spring Base


Light Spring Extreme

Light Spring Extreme with

synchronous condenser

conversion

Synchronous Condenser Conversion Results in

Acceptable Performance in Extreme Sensitivity

Reinforcements for Extreme sensitivity: 3 condensers total ~1700MVA plus ~500 MVAr shunt banks.

Disturbance: Aeolus bus

fault and line trip

1

3

2

4

1

2

3

4 ERSTF: this is

transient voltage

collapse.

Pessimistic dynamic load

model plays a

key role

ERSTF: 80%

reduction in coal

dispatch still

stable

17


Study Conclusions

The Western Interconnection can be made to work

well in the first minute after a big disturbance with

both high wind and solar and substantial coal displacement, using good, established planning and

engineering practice and commercially available

technologies.

The following detailed conclusions were word-

smithed by Technical Review Committee and includes

the appropriate caveats.

18


Thank you! [email protected]

http://www.nrel.gov/docs/fy15osti/62906.pdf (full report)

http://www.nrel.gov/docs/fy15osti/62906-ES.pdf (executive summary)

19


http://www.nrel.gov/docs/fy15osti/62906.pdf

http://www.nrel.gov/docs/fy15osti/62906.pdf

http://www.nrel.gov/docs/fy15osti/62906-ES.pdf




Heavy Summer Load Study Scenarios

Wind 2.1PV 1.1

CSP 0.4DG 0.0

Others 64.9

Wind 0.0

PV 0.0CSP 0.0DG 0.0

Others 33.3

Wind 1.7PV 0.0

CSP 0.0

DG 0.0Others 18.1

Wind 0.8 PV 0.1

CSP 0.0

DG 0.0

Others 53.0


Wind 2.1PV 5.8

CSP 3.1

DG 5.4

Others 54.6

Wind 6.9

PV 0.2CSP 0.0DG 0.3

Others 29.8

Wind 2.6 PV 1.3

CSP 0.0

DG 0.9Others

15.6

Wind 1.8 PV 3.8CSP 3.5

DG 2.9

Others 36.9


Base Case High Mix Case

WECC-Wide Summary(1)

Heavy Summer Base

(2)

Heavy Summer High Mix

Wind (GW) 5.6 14.3

Utility-Scale PV (GW) 1.2 11.2

CSP (GW) 0.4 6.6

Distributed PV (GW) 0.0 9.4

Total = 7.2 41.5

Penetration(3)

(%) = 4% 20%

(1) Western Electricity Coordinating Council includes parts of Canada and Mexico, (2) Provided by WECC, (3) Penetration is % of total generation for this snapshot. 20


Critical Disturbances in the West

Pacific DC

Intertie

Selected by Technical Review Committee:

• Palo Verde Nuclear Plant (2 of 3 units for ~2,750 MW)

• Pacific DC Intertie (Maximum north-to-south power flow ~3,100 MW)

21


Frequency Control on Utility-scale PV Plants


Light Spring High Mix with governor controls on

utility-scale PV plants

~80% of utility-scale PV plants (i.e., new ones) had these controls, for a total of 820 MW initial curtailment out of 10.2 GW production.


1

2

2

1

ERSTF: 820 MW of Fast Frequency Response

FRO Base Hi-Mix Wind

Governor

Control

Wind

Inertial

Control

Wind

Governor

and

Inertial

Controls

Utility-

scale PV

Governor

Control

Energy

Storage

with

Governo

r Control

Extreme

Hi-Mix

WECC 840 1352 1311 1610 1323 1571 2065 1513 1055

22


Transient Stability Conclusions

For the conditions studied, system-wide transient stability can be maintained with high levels of wind and solar generation with both traditional and non-traditional approaches.

Traditional transmission system reinforcements to address stability, voltage, and thermal problems include:

• Transformers • Shunt capacitors, (dynamic reactive support) • Local lines

Non-traditional approaches are also effective at improving transient stability including:

• Synchronous condenser conversions • New wind and solar controls

There are caveats in report. 23


Frequency Response Conclusions For the conditions studied:

• System-wide FR can be maintained with high levels of wind and solar generation

if local stability, voltage, and thermal problems are addressed with traditional transmission system reinforcements (e.g., transformers, shunt capacitors, local lines).

• Limited application of non-traditional frequency-responsive controls on wind,

solar PV, CSP plants, and energy storage are effective at improving both frequency

nadir and settling frequency, and thus FR. Refinements to these controls would further

improve performance.

• Individual BA FR may not meet its obligation without additional FR from resources

both inside and outside the particular area. As noted above, non-traditional approaches

are effective at improving FR. Current operating practice uses more traditional approaches

(e.g., committing conventional plants with governors) to meet all FR needs.

• Using new, fast-responding resource technologies (e.g., inverter-based controls) to

ensure adequate FR adds complexity, but also flexibility, with high levels of wind and solar

generation. Control philosophy will need to evolve to take full advantage of easily

adjustable speed of response, with additional consideration of the location and size of the

generation trip.

• For California, adequate FR was maintained during acute depletion of headroom from

afternoon drop in solar production, assuming the ability of California hydro to provide FR.

24


Transient Stability Conclusions

For the conditions studied:

• System-wide transient stability can be maintained with high levels of wind and solar generation if local stability, voltage, and thermal problems are addressed with traditional transmission system reinforcements (e.g., transformers, shunt capacitors, local lines). With these reinforcements, an 80% reduction in coal plant commitment, which drove SNSP to 56%, resulted in acceptable transient stability performance.

• With further reinforcements, including non-standard items such as synchronous condenser conversions, a 90% reduction in coal plant commitment, which drove SNSP to 61%, resulted in acceptable transient stability performance.

• Additional transmission and CSP generation with frequency-responsive controls are effective at improving transient stability.

25


Other Conclusions • Accurate modeling of solar PV, CSP, wind, and load behavior is extremely important when

analyzing high-stress conditions, as all of these models had an impact on system

performance.

• Attention to detail is important. Local and locational issues may drive constraints on both FR

and transient stability.

• The location of generation tripping, e.g., DG vs. central station, is not as important as the

amount of generation that is tripped. However, widespread deliberate or common-mode DG

tripping after a large disturbance has an adverse impact on system performance. It is

recommended that practice adapt to take advantage of new provisions in IEEE 1547 that

allow for voltage and frequency ride-through of DG to improve system stability.

• Further analysis is needed to determine operational limits with low levels of synchronous

generation in order to identify changes to path ratings and associated remedial action

schemes, as well as quantify the impact of DG on transmission system performance.

• Because a broad range of both conventional and non-standard operation and control options improved system performance, further investigation of the most economic and

effective alternatives is warranted. This should include consideration of the costs and

benefits of constraining commitment and dispatch to reserve FR, as well as the capital and

operating costs of new controls and equipment.

26

GridEx IIIOperating CommitteeUpdate

Jacksonville, FLMarch 11, 2015

Presentation 8.k


Organizations and ParticipantsDesignation Expectations Return on Investment

Your Organization

Active Organization

• Participate in NERC planning conferences and training sessions

• Engage in dynamic internal exercise play and external information sharing and coordination

• Tailor/adapt scenario to suit organization objectives and play

• Communicate externally to other exercise participants

• Close interaction with other BPS entities and relevant law enforcement and government agencies

• Incident response training opportunity

• Provide input to develop scenario and identify after action findings

• Use exercise for requirements evidence

Observing Organization

• Limited resources/support from NERC

• Receive baseline scenario injects

• Tabletop or discuss scenario events internally

• No interaction with Active Organizations

• Valuable internal training opportunity

• Gain experience to participate in future exercises as an Active Organization

Your Organization’s Participants

Planner

• Participate in planning conferences

• Designate and orient players and controllers

• Customize injects for more realism

• Provide after action feedback

• Opportunity to provide input on all planning materials

• Provide input to develop scenario and identify after action findings

• Observe player response and activities

Player• Participate in orientation and training

• Engage in 2 days of live exercise play and provide after action feedback to planners

• Realistic training opportunity with broad set of BPS entities

• Build and strengthen relationships


GridEx III and Reliability Coordinators


16 Reliability Coordinators

Code Name

ERCOT ERCOT ISO

FRCC Florida Reliability Coordinating Council

HQT HydroQuebec TransEnergie

ISNE ISO New England Inc.

MISO Midcontinent Independent System Operator

NBPC New Brunswick Power Corporation

NYIS New York Independent System Operator

ONT Ontario - Independent Electricity System Operator

PJM PJM Interconnection

SPC SaskPower

SOCO Southern Company Services, Inc.

SPP Southwest Power Pool

TVA Tennessee Valley Authority

VACS VACAR-South

PEAK Peak Reliability

AESO Alberta Electric System Operator

The GEWG has SMEs from 12 RCs across the BES to support GridEx planning and conduct


Timeline

RCs identify Active Organizations in their control area

RCs establish and participate in RC-to-RC and RC-to-Entity coordination calls

RCs and entities understand and develop customized injects

Reliability Coordinator Planning Activities

GridEx Working

Group

Initial Planning

Phase

Mid-term Planning

Phase

Final Planning

Phase

GridEx III

After Action

Confirm exercise infrastructure

Finalize attack vectors and impacts

Work on scenario narrative

Finalize baseline MSEL

Develop Controller and Player materials

Draft After Action Survey

Send injects and oversee player actions

Capture player actions and findings

Facilitate Executive Tabletop

Distribute survey

Analyze findings and lessons learned

Draft Final Report

Finalize custom injects with RCs

Distribute materials

Conduct training

Set up venue and logistics

December 10 2014 March 11-12 June 10-11 Sept 1st Wk Nov 18-19 Q1 2016January 23

Establish Working Group Members Establish Mail

list GridEx

Awareness

Confirm objectives

Establish boundaries

Confirm tools

2015 Conference Dates

GEWGReform

ACSETF Report –Recommendation UpdatesMichael Lombardi, Manager of System Studies, NPCCOperating Committee/Planning Committee MeetingsMarch 2015

Presentation 8.l


Background

• The AC Substation Equipment Task Force (ACSETF) Report was submitted to the NERC Operating Committee (OC) and Planning Committee (PC) for approval at the December 2014 meeting Insufficient data was available to identify the root cause for the equipment

failures investigated Recommendations were made at conceptual and programmatic levels

• December 2014 – NERC PC/OC approved the ACSETF Report and directed the ACSETF to: Identify the high priority recommendations Refine the high priority recommendations to be actionable Provide a status update on the high priority recommendations at the

March 2015 PC Meeting


Bus Configuration

• Report Recommendation: NERC should consider the impact of bus configuration on ac transmission

circuit outages

• Recommendation Refinement Events Analysis shall identify the contribution that bus configuration had

on disturbance events associated with ac substation equipment failures

• Recommendation Status -- Complete Addendum for Events with Failed Station Equipment was completed and

posted on the NERC Event Analysis Program web page on February 17, 2015

http://www.nerc.com/pa/rrm/ea/Pages/EA-Program.aspx


Data Collection - EA

• Report Recommendation: NERC and entities should investigate a consistent method for collection of

ac substation equipment failure data using industry guidelines and share the results with applicable organizations

High-voltage equipment bushings should be categorized and treated as a completely separate piece of substation equipment

• Recommendation Refinement NERC Event Analysis (EA) shall include in its Reference Material for Event

Analysis an Addendum to provide a checklist of considerations for collection of ac substation equipment failure data

• Recommendation Status -- Complete Addendum for Events with Failed Station Equipment was completed and

posted on the NERC EA Program web page on February 17, 2015

http://www.nerc.com/pa/rrm/ea/Pages/EA-Program.aspx


NERC EA Program Web Page


Reference Material for EA

• Addendum for Events with Failed Station Equipment: Promotes Common Approach and Standard Methodology for Event Data

Collection Can be easily revised and updated, as needed

• Additional data collection: Will aid in root cause analysis of future events (high priority) Will improve analysis and trending performed by the Event Analysis

Subcommittee (EAS) Trends Working Group (TWG)


Data Collection - TADS

• Report Recommendation: NERC should incorporate data from other sources and analyze the impact on Bulk

Electric System (BES) reliability

• Recommendation Refinement TADSWG to evaluate the collection of addition details regarding initiating and/or

sustaining cause information for AC station equipment failures

• Recommendation Status -- Complete TADSWG evaluated the request for the collection of addition details TADSWG determined that the additional details requested by the ACSETF does not

provide any meaningful added value to existing TADS data and resulting analysis of TADS data

TADSWG believed that the ACSETF request was duplicative to data collection efforts already in place by the North American Transmission Forum (NATF) and indicated NERC staff is in discussion with NATF to establish information sharing

TADSWG recommended that engaging other existing industry efforts (NATF, et al) would provide better insights into AC station equipment failures


Summary

• ACSETF had insufficient data to: Identify the root cause of substation equipment failures Identify actions to prevent recurrence

• Additional data collection through the Events Analysis Process will aid in root cause analysis of future events (high priority) Additional data collection will improve analysis and trending performed by

the EAS TWG

• ACSETF Report medium and low priority recommendations can be: Tabled at this time Re-visited or reconsidered based on results and information obtained

through implementation of high priority items

• PC to consider the future of ACSETF up to but not limited to termination of the Task Force

Energy Infrastructure Modeling and Analysis Division: Research Status Report

March 10 - 11, 2015

NERC Operating Committee

Emmanuel Taylor – Electrical Engineer

Presentation 8.m

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Presentation Outline

1. Background on OE and EIMA

2. Research project review

This presentation will cover the following topics:

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Core Purpose of OE

OE drives grid modernization by improving energy system:

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Energy Infrastructure Modeling and Analysis

EIMA addresses dynamics, complexity, and uncertainty, through:

to improve energy infrastructure decision making.

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EIMA Has Two R&D Programs

Transmission Reliability Advanced Grid Modeling

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Research project highlighted:

Focus of this Research Update

Project Title PI Institution

Frequency Responsive Demand

Karanjit Kalsi, Ph.D.,

Pacific Northwest National Laboratory

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Principal Investigator:

Karanjit Kalsi, Ph.D., PNNL

Wei Zhang, Ph.D., Ohio State University

Matt Donnelley, Ph.D., Montana State University

Research Objective:

Provide a framework to facilitate large-scale deployment of frequency responsive end-use devices. Test and validate control strategy using large-scale simulations and field demonstrations

Institution:

Pacific Northwest National Laboratory

Project Timeline:

August 2010 – September 2014

Significance:

Allows for load side frequency control, which may be helpful under conditions of high renewable penetration.

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Thermostatically controlled loads are switched on/off in order to counter the effects of frequency deviations. The aggregate effect is examined across WECC.

Jeff Dagle; “Frequency Responsive Demand”; CERTS Program Review, September 16, 2014, Berkeley, CA

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140 devices are controllable. 12 load buses are monitored. 3 tie lines are monitored. WECC high summer 2014 and low winter 2022 models are used.


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Disconnecting frequency responsive load during a disturbance decreases the system’s maximum frequency deviation and the steady-state frequency error.


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The benefits are consistent across the broad geographical area under study, and remain consistent in the future planning cases under study.


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The benefits are consistent across the broad geographical area under study, and remain consistent in the future planning cases under study.


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Grid friendly appliances are controlled to exhibit a droop-like response to changes in frequency. IEEE 68 bus test case is used to evaluate the response.


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The actual behavior of grid friendly appliances in practice, may differ from the model generated, due to cutoff frequencies and localized measurements.


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Response for 250 MVA generator trip and a 1350 MVA generator trip. The cutoff frequency bias has an impact on the effectiveness of this method.


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Response for 250 MVA generator trip and a 1350 MVA generator trip. Number of GFAs and disturbance size both impact the effectiveness of this method.


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Past Accomplishments:

• Concept demonstrated via large scale simulation

• Significant parameters identified

• Supervisory control implemented with probabilistic switching

• Autonomous control introduced

Next Steps:

• Droop-like load on full WECC system model

• Hardware-in-the-loop testing at PNNL

• Potential impacts on distribution system

• Potential play in ancillary service market

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The feedback of the OC on the value of this project is appreciated.

Feedback and Insights

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Contact Information

Office of Electricity Delivery and Energy Reliability U.S. Department of Energy 1000 Independence Ave, S.W. Washington, DC 20585 Office: 202-586-1313 Email: [email protected]

Emmanuel J. Taylor, Ph.D.

Project 2014-03 Update

Dave Souder, Project 2014-03 ChairNERC Operating CommitteeMarch 10-11, 2015

Presentation 8.n


• IRO-001-4, IRO-002-4, IRO-008-2, IRO-010-2, IRO-014-3, IRO-017-1, TOP-002-4, TOP-003-3 and 2 definitions adopted by NERC Board of Directors -November 2014.

• TOP-001-3 adopted by NERC Board of Directors - February 2015• TOP/IRO Standards submitted to FERC - March 2015• Projected Timeline: All standards except proposed TOP-003-3 and proposed IRO-010-2 become

effective 12 months after FERC Approval (that is, the 1st day of the 1st calendar quarter that is 12 months after the date the standard is approved by FERC).

TOP-003-2 and IRO-010-2 become effective 9 months after FERC approval TOP-003 R5 and IRO-010 R3; they become effective 12 months after FERC Approval

in order to properly respond to the data specification requests. Prerequisite approval of COM-001-2 and definition of Operating Instruction is

required either before or at the same time as the revised TOP/IRO standards.

Revisions to TOP/IRO Reliability Standards

Integration of Variable Generation Task ForceSummary and Recommendations of 12 Tasks Report

Noha Abdel-Karim, Senior Engineer, NERCOperating Committee Meeting March 10-11, 2015

Presentation 8.o


Planning Committee Tasks Operating Committee Tasks

• Planning Tasks Task 1.1 – Generic Wind Turbine Models Task 1.5 – Incorporating PHEV, Storage,

DR into Planning Process Task 1.8 – Incorporating Variable DER

into the Planning Process

• Interconnection Tasks Task 1.3 – Interconnection Requirements Task 1.7 – Reconciliation of Order 661-A

and IEEE 1547

• Probabilistic Tasks Task 1.2 – Capacity Value Methods Task 1.4 – Flexibility Requirements and

Metrics Task 1.6 – Probabilistic Methods

• Operations Tasks Task 2.1 – VG Power Forecasting for

Operations Task 2.3 – Ancillary Service and BA

Solutions to Integrate VG Task 2.4 – Improved Operating Practices

with VG

• Interconnection Tasks Task 2.2 – BA Communication

Requirements

IVGTF Work Plan Organization


Overview:

• The final report recognizes the accomplishments of the 12 IVGTF efforts that address broader and detailed aspects of integration large amounts of variable generation.

• The IVGTF leadership summarized and refreshed each of the task’s recommendations and conclusions.

Objectives:

• Summarize all recommendations from the task force with an objective to evaluate the effects of large-scale integration of VG and identify the long-term reliability considerations needed to ensure the reliability of the BPS

• Determine the status of these recommendations by identifying a transition plan next steps for NERC.

Summary Report - Overview


• IVGTF Transition Plan –Summary Identifies the next steps for the IVGTF recommendations, including

recommendations that are still relevant for possible revisions to standards, additions to technical guidelines, suggestions for further research, or recommendations for operating and planning best practices –(Appendix I of the report).

• IVGTF Transition Plan –Development Coordination effort with working groups and NERC Standard

department. Integration into the summary report ( Work in progress in finalizing

some transition categories).

IVGTF Final ReportTransition Plan Updates


• Appendix I contains an IVGTF Transition Plan that identifies the next steps for Transition plan : covers range of topics classified them according to next phases of considerations into the following categories: Standards Drafting Team(s) Enhancements to Modeling Definition – Revisions or Addition By NERC Operating Practices and Technical Guidelines Planning Approaches – Technical Guidelines Research and Development NERC Training and Education Operators Training and Data Collection Essential Reliability Services Task Force (ERSTF) No Action (i.e., recommendation is out of scope and is not applicable, such as due

to market or commercial action improvements, or has been addressed by different projects).

IVGTF Final ReportTransition Plan Updates


Next Steps:• PC review the IVGTF Summary report and provide comments and

feedback on IVGTF transition Plan, which delegates the effort to the NERC LTRA, Special Assessments, ERSTF, possible revisions to standards, additions to technical guidelines, suggestions for further research, or recommendations to operating and planning best practices.

• Report Final Release: Next PC meeting, June 2015.• Disband the IVGTF and delegate this continuing monitoring effort to

NERC reliability assessments and special assessment reports.• NERC staff recommends transitioning follow-on work to the Essential

Reliability Services Task Force. • NERC staff will continue monitor the progress of the IVGTF

recommendations coordinate technical discussions between standards drafting teams and the OC/PC.

IVGTF – NEXT Steps

FAC-003 Research ProjectOverview of Validation Testing ofMinimum Vegetation Clearance Distances

Robert W. CummingsDirector, Reliability Initiatives and System AnalysisOperating Committee & Planning Committee MeetingMarch 10-11, 2015

Presentation 8.p


• March 2013 —NERC directed to conduct testing to support appropriate Minimum Vegetation Clearance Distances (MVCD) in FAC-003-3 (Order 777)

• July 2013 — Project plan submitted to FERC• January 2014 — Advisory team assembled and project initiated• October 2014 — Planned testing completed by NERC and EPRI

Background


• Selected representative set of vegetation in and around transmission rights-of-way

• Switching impulse tests performed for representative combinations of vegetation shapes and voltages for:

Vertical (grow-in)

Horizontal (blow-in)

Test Plan


• Switching impulse tests on representative hybrid natural trees fitted with well-grounded metal center rod Vegetation with highest likelihood of flashover Metal rod perturbs electrical field more than vegetation

• Conservatism shown by re-testing of configurations yielding lowest gap factor with wooden dowels replacing metal rods Wooden dowel more closely represents electric field effects of natural

vegetation

• Completed final series of withstand tests with fully natural trees without attachments to verify the gap factors determined in the above testing

Gap Factor Testing Plan


• Preliminarily testing demonstrated that a gap factor of 1.0 may be more appropriate than the present value of 1.3 contained in FAC-003-3

Preliminary Findings

Test Results for Hybrid Trees with Metal Rod

Test Configuration Tree Shape 230 kV 345 kV 500 kV 765 kV

Vertical/ Grow-in

Trimmed Tree 1.15 1.29 1.16 1.21

Columnar 1.19 1.42 1.16 1.24

Pyramidal 1.44 1.34 1.27 1.43

Horizontal/ Blow-inSingle Branch 1.44 1.39 1.35 1.41

Columnar 1.02 1.17 1.21 1.25


• Comparison of gap factors determined for conductor-to-vegetation gap configuration and system voltage yielding lowest gap factor during metal rod test phase

Preliminary Findings

Test Configuration Tree Shape Test Phase Gap Size Gap Factor U50

Horizontal/ Blow-in Columnar

Metal Rod 38.6” 1.02 379 kV

Wooden Dowel 38.6” 1.22 451 kV

TreeOnly 38.6” 1.23 459 kV


• Existing FAC-003-3 gap factor of 1.3 versus preliminarily determined gap factor of 1.0

• Shows increase in MVCD of ½ foot to 3½ feet with 1.0 gap factor (230 kV and above)

MVCD Comparison

MVCD Comparison at Sea Level

Nominal System Voltage (kV)

MVCD @ 1.3(ft)

MVCD @ 1.0(ft)

Increase in MVCD (ft)

765 8.20 11.63 3.43

500 5.15 7.04 1.89

345 3.19 4.25 1.06

230 3.03 4.03 1.00


• NERC may use other communication tools to socialize the conclusions developed through testing Webinar Informational Alert

• June 2015 — File final NERC report with FERC• Likely a narrowly defined Standard Authorization Request will

be needed to adjust MVCD values in FAC-003-3

Going Forward


• Applicable Transmission Owners and Generator Owners may consider adjusting MVCDs prior to Spring maintenance

Considerations

Nominal AC

System Voltage

(kV)

MVCD at 1.0 Gap Factor (ft)Sea

Level up to 500 ft

Over 500 ftup to

1,000 ft

Over 1,000 ft

up to2,000 ft

Over 2,000 ft

up to3,000 ft

Over 3,000 ft

up to4,000 ft

Over 4,000 ft

up to5,000 ft

Over 5,000 ft

up to6,000 ft

Over 6,000 ft

up to7,000 ft

Over 7,000 ft

up to8,000 ft

Over 8,000 ft

up to9,000 ft

Over 9,000 ft

up to10,000 ft

Over 10,000 ft

up to11,000 ft

765 11.63 11.68 11.90 12.07 12.24 12.42 12.61 12.8 13.00 13.14 13.34 13.49

500 7.04 7.08 7.24 7.37 7.50 7.63 7.77 7.92 8.07 8.17 8.34 8.45

345 4.25 4.28 4.39 4.48 4.57 4.66 4.76 4.87 4.97 5.05 5.17 5.25

287 5.23 5.26 5.39 5.49 5.60 5.71 5.82 5.94 6.07 6.15 6.29 6.39

230 4.03 4.06 4.16 4.25 4.33 4.43 4.52 4.62 4.73 4.80 4.91 4.99

161 2.69 2.71 2.79 2.85 2.91 2.98 3.04 3.12 3.20 3.25 3.33 3.39

138 2.28 2.29 2.36 2.41 2.47 2.52 2.58 2.65 2.71 2.76 2.83 2.88

115 1.87 1.89 1.94 1.99 2.03 2.08 2.13 2.19 2.24 2.28 2.34 2.39

88 1.53 1.54 1.59 1.62 1.66 1.70 1.75 1.79 1.84 1.87 1.92 1.96

69 1.08 1.09 1.13 1.15 1.18 1.21 1.24 1.27 1.31 1.33 1.37 1.40


Neil BurbureNorth American Electric Reliability Corporation1325 G Street NW, Suite 600Washington, DC 20005-3801202-400-3015 office | 404-904-5034 [email protected]

Contact Information



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