Operating Committee MeetingPresentationsMarch 10-11, 2015 | Jacksonville, FL
*All presentations are posted with the written consent of the presenters.
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
• 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
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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
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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
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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
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• 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
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• 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
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)
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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.
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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)
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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
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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
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
RELIABILITY | ACCOUNTABILITY3
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
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
• 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
RELIABILITY | ACCOUNTABILITY6
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?
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY3
• 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
RELIABILITY | ACCOUNTABILITY4
• 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
RELIABILITY | ACCOUNTABILITY5
• 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
RELIABILITY | ACCOUNTABILITY6
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
RELIABILITY | ACCOUNTABILITY7
• 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.
LL20150202 Mutual Coupling when Setting Ground Instantaneous Overcurrent Elements
RELIABILITY | ACCOUNTABILITY8
• 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
LL20150202 Mutual Coupling when Setting Ground Instantaneous Overcurrent Elements
RELIABILITY | ACCOUNTABILITY9
• 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
RELIABILITY | ACCOUNTABILITY10
• 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)
LL20150301 Importance of Backup Energy Management System Failover Testing after
Network Device Reconfiguration
RELIABILITY | ACCOUNTABILITY11
• 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
LL20150301 Importance of Backup Energy Management System Failover Testing after
Network Device Reconfiguration
RELIABILITY | ACCOUNTABILITY12
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
LL20150301 Importance of Backup Energy Management System Failover Testing after
Network Device Reconfiguration
RELIABILITY | ACCOUNTABILITY13
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.
LL20150301 Importance of Backup Energy Management System Failover Testing after
Network Device Reconfiguration
RELIABILITY | ACCOUNTABILITY14
• 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
RELIABILITY | ACCOUNTABILITY15
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
RELIABILITY | ACCOUNTABILITY16
• 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
RELIABILITY | ACCOUNTABILITY2
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.
RELIABILITY | ACCOUNTABILITY3
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)
RELIABILITY | ACCOUNTABILITY4
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)
RELIABILITY | ACCOUNTABILITY5
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.
RELIABILITY | ACCOUNTABILITY6
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
RELIABILITY | ACCOUNTABILITY7
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
RELIABILITY | ACCOUNTABILITY8
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
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY3
• 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
RELIABILITY | ACCOUNTABILITY4
• 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.
RELIABILITY | ACCOUNTABILITY5
• 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
RELIABILITY | ACCOUNTABILITY7
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
RELIABILITY | ACCOUNTABILITY9
CP-1 Proposal
Figure 2 Standards and Requirements with Most Occurrences of Serious Risk Violations
RELIABILITY | ACCOUNTABILITY10
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
RELIABILITY | ACCOUNTABILITY11
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
RELIABILITY | ACCOUNTABILITY12
ALR CP-2 Data Collection
Find and Fix these
To reduce the #and magnitude of these
RELIABILITY | ACCOUNTABILITY14
• 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
RELIABILITY | ACCOUNTABILITY15
• 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
RELIABILITY | ACCOUNTABILITY16
• 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)
RELIABILITY | ACCOUNTABILITY17
• 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
Recommendations from the Compliance Metrics White Paper (2 of 4)
RELIABILITY | ACCOUNTABILITY18
• 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
Recommendations from the Compliance Metrics White Paper (3 of 4)
RELIABILITY | ACCOUNTABILITY19
• 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
Recommendations from the Compliance Metrics White Paper (4 of 4)
NERC Operating Committee Strategic Plan 2015 - 2019
Alan BernNERC Operating Committee MeetingMarch 10, 2015
Presentation 8.d
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY9
• 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
RELIABILITY | ACCOUNTABILITY2
• Peter Brandien• Ken McIntyre• Jerry Mosier• Pierre Paquet
Working Group Members
RELIABILITY | ACCOUNTABILITY3
• 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.
RELIABILITY | ACCOUNTABILITY4
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”
RELIABILITY | ACCOUNTABILITY5
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
RELIABILITY | ACCOUNTABILITY2
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
RELIABILITY | ACCOUNTABILITY3
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)
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
• Know our data• Decouple data from applications• Enable ERO Enterprise data consumption Ad-hoc reporting Analytics Data sharing Historical trending
Solution
RELIABILITY | ACCOUNTABILITY6
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
RELIABILITY | ACCOUNTABILITY7
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
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY3
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
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
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
Frequency Data Problems Found
RELIABILITY | ACCOUNTABILITY6
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
Frequency Data Problems Found
RELIABILITY | ACCOUNTABILITY8
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
RELIABILITY | ACCOUNTABILITY9
• 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
RELIABILITY | ACCOUNTABILITY2
In less than three months time……
NERC Advisory was developed, reviewed and approved. Advisory issued on February 5, 2015.
NERC Advisory
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
No Frequency Algorithm in DCS
Frequency Algorithm in DCS
175 MW GE7FA Gas GE Mark VI Turbine
3/3/2015
Tale of Two Tales
RELIABILITY | ACCOUNTABILITY6
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%
RELIABILITY | ACCOUNTABILITY7
Proportional Response vs. Step Response
More complex issue…. Almost every OEM does it differently. For some this is complicated to modify.
What we learned
RELIABILITY | ACCOUNTABILITY9
• 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
RELIABILITY | ACCOUNTABILITY10
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Production/Dispatch in GW
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
Frequency Response Analysis
5
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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 High Mix
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Disturbance: Trip 2 Palo Verde units (~2,750MW)
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
Transient Stability Analysis
11
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
Transient Stability in Northeastern WECC
L
Aeolus
500kV
Large Coal Plants
13
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
ne
rati
on
co
mm
itm
en
t (b
ase
d o
n M
VA
ra
tin
g)
He
av
y S
um
me
r B
ase
He
av
y S
um
me
r B
ase
He
av
y S
um
me
r B
ase
He
av
y S
um
me
r B
ase
He
av
y S
um
me
r H
igh
Mix
He
av
y S
um
me
r H
igh
Mix
He
av
y S
um
me
r H
igh
Mix
He
av
y S
um
me
r H
igh
Mix
California Desert Southwest Northeast Northwest
Lig
ht
Sp
rin
g B
ase
Lig
ht
Sp
rin
g B
ase
Lig
ht
Sp
rin
g B
ase
Lig
ht
Sp
rin
g B
ase
Lig
ht
Sp
rin
g H
igh
Mix
Lig
ht
Sp
rin
g H
igh
Mix
Lig
ht
Ex
tre
me
Se
nsi
tiv
ity
Lig
ht
Sp
rin
g H
igh
Mix
Lig
ht
Ex
tre
me
Se
nsi
tiv
ity
Lig
ht
Ex
tre
me
Se
nsi
tiv
ity
Lig
ht
Ex
tre
me
Se
nsi
tiv
ity
Lig
ht
Sp
rin
g H
igh
Mix
16
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
Dave Johnson Voltage
Light Spring Base
Light Spring High Mix
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Production/Dispatch in GW
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
Production/Dispatch in GW
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
Frequency Control on Utility-scale PV Plants
Light Spring High Mix
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.
Disturbance: Trip 2 Palo Verde units (~2,750MW)
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
Western Wind and Solar Integration Study - 3: Transient Stability and Frequency Response. N.W. Miller, GE Energy Consulting. Funded by DOE
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
RELIABILITY | ACCOUNTABILITY2
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
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY5
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
RELIABILITY | ACCOUNTABILITY2
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
RELIABILITY | ACCOUNTABILITY3
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
RELIABILITY | ACCOUNTABILITY4
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
RELIABILITY | ACCOUNTABILITY6
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)
RELIABILITY | ACCOUNTABILITY7
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
RELIABILITY | ACCOUNTABILITY8
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
2 2
Presentation Outline
1. Background on OE and EIMA
2. Research project review
This presentation will cover the following topics:
4 4
Energy Infrastructure Modeling and Analysis
EIMA addresses dynamics, complexity, and uncertainty, through:
to improve energy infrastructure decision making.
6 6
Research project highlighted:
Focus of this Research Update
Project Title PI Institution
Frequency Responsive Demand
Karanjit Kalsi, Ph.D.,
Pacific Northwest National Laboratory
7 7
Frequency Responsive Demand
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.
8 8
Frequency Responsive Demand
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
9 9
Frequency Responsive Demand
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.
Jeff Dagle; “Frequency Responsive Demand”; CERTS Program Review, September 16, 2014, Berkeley, CA
10 10
Frequency Responsive Demand
Disconnecting frequency responsive load during a disturbance decreases the system’s maximum frequency deviation and the steady-state frequency error.
Jeff Dagle; “Frequency Responsive Demand”; CERTS Program Review, September 16, 2014, Berkeley, CA
11 11
Frequency Responsive Demand
The benefits are consistent across the broad geographical area under study, and remain consistent in the future planning cases under study.
Jeff Dagle; “Frequency Responsive Demand”; CERTS Program Review, September 16, 2014, Berkeley, CA
12 12
Frequency Responsive Demand
The benefits are consistent across the broad geographical area under study, and remain consistent in the future planning cases under study.
Jeff Dagle; “Frequency Responsive Demand”; CERTS Program Review, September 16, 2014, Berkeley, CA
13 13
Frequency Responsive Demand
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.
Jeff Dagle; “Frequency Responsive Demand”; CERTS Program Review, September 16, 2014, Berkeley, CA
14 14
Frequency Responsive Demand
The actual behavior of grid friendly appliances in practice, may differ from the model generated, due to cutoff frequencies and localized measurements.
Jeff Dagle; “Frequency Responsive Demand”; CERTS Program Review, September 16, 2014, Berkeley, CA
15 15
Frequency Responsive Demand
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.
Jeff Dagle; “Frequency Responsive Demand”; CERTS Program Review, September 16, 2014, Berkeley, CA
16 16
Frequency Responsive Demand
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.
Jeff Dagle; “Frequency Responsive Demand”; CERTS Program Review, September 16, 2014, Berkeley, CA
17 17
Frequency Responsive Demand
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
19 19
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
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY2
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
RELIABILITY | ACCOUNTABILITY3
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
RELIABILITY | ACCOUNTABILITY4
• 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
RELIABILITY | ACCOUNTABILITY5
• 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
RELIABILITY | ACCOUNTABILITY6
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
RELIABILITY | ACCOUNTABILITY2
• 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
RELIABILITY | ACCOUNTABILITY3
• 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
RELIABILITY | ACCOUNTABILITY4
• 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
RELIABILITY | ACCOUNTABILITY5
• 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
RELIABILITY | ACCOUNTABILITY6
• 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
RELIABILITY | ACCOUNTABILITY7
• 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
RELIABILITY | ACCOUNTABILITY8
• 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
RELIABILITY | ACCOUNTABILITY9
• 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
RELIABILITY | ACCOUNTABILITY10
Neil BurbureNorth American Electric Reliability Corporation1325 G Street NW, Suite 600Washington, DC 20005-3801202-400-3015 office | 404-904-5034 [email protected]
Contact Information