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Operating Committee MeetingPresentationsAtlanta, GA | December 9-10, 2014
*All presentations are posted with the written consent of the presenters.
NERC Lessons Learned Summary
Operating Committee MeetingDecember 9-10, 2014
Presentation 5.c.i
RELIABILITY | ACCOUNTABILITY2
Three NERC lessons learned (LL) were published in December 2014• LL20141201 Control System Network Switch Failure• LL20141202 Bus Differential Power Supply Failure• LL20141203 Loss of Multiple Generators Due to Control Air
Problems
NERC Lessons Learned Published in December 2014
RELIABILITY | ACCOUNTABILITY3
LL20141201 Control System Network Switch Failure
A partial failure of one of the redundant core switches on a control system mesh network caused a data communication failure. This resulted in two generating units tripping simultaneously, losing a total net output of 1130 MW. • The partial failure of the primary core switch kept the switches ports
open for traffic• The secondary switch detected the partial failure and opened its ports
for communication• This caused the network to loop, generating a data storm• This blocked the communication between the boiler controls and the
burner management control processors on both units which eventually tripped the units
• The “loss of fault tolerant burner control system communications processor (BCS CP)” was the immediate cause of the unit trips
RELIABILITY | ACCOUNTABILITY4
Lessons Learned:• Redundant devices are implemented to increase reliability, but
implementation of such devices may introduce unanticipated failure scenarios if not fully tested
• Whenever practical, consider a reliable external monitor that can provide diagnostics and alarming to reduce the risk of an undetected failure
• Consideration should be given to testing and verification of the network topology and fail-over function
LL20141201 Control System Network Switch Failure
RELIABILITY | ACCOUNTABILITY5
LL20141202 Bus Differential Power Supply Failure
A microprocessor bus differential relay scheme hardware failure initiated a double bus trip on the BES, resulting in a loss of 58,000 customers• The “A” phase differential relay power supply capacitor began
degrading and caused the analog to digital converter to provide erroneous current and voltage
• This resulted in an “A” phase differential trip for bus-1 and bus-2; the voltage supervision was not effective since the degraded capacitor also provided erroneous voltage values used in the differential element supervision
• This version of the relay does not monitor the power supply internal logic voltages, so the relay did not take itself out of service
• The double bus trip resulted in a sustained loss of over 58,000 customers
RELIABILITY | ACCOUNTABILITY6
Lessons Learned• For high-impact schemes, the supervision should be
independent of the tripping device• In this case, the mode of failure affected the supervising
element along with the tripping element (current) being measured
• The design of this scheme should have involved increased security since one scheme protects both busses
• Relay manufacturers should ensure there is sufficient device self-monitoring to allow the device to be disabled prior to causing an unwanted trip Manufacturers must communicate the risks clearly to the owners and
immediately when the problem is discovered
LL20141202 Bus Differential Power Supply Failure
RELIABILITY | ACCOUNTABILITY7
• On April 17, 2013, NERC published Lesson Learned #LL20130402. That lesson learned was focused on the inadequate separation of the critical ac power supply of a generating plant’s air system. When the air system was lost, it contributed to the loss of two large generators, creating a system disturbance. Since LL20130402 was published, the NERC Event Analysis (EA) staff has identified other instances of generating plants tripping multiple generators due to the loss of station air when the station’s air systems are tied together.
LL20141203 Loss of Multiple Generators Due to Control Air Problems
RELIABILITY | ACCOUNTABILITY8
• In one example, power plant “A” was equipped with two air headers, which are normally separated. The plant experienced a problem with an air compressor that was serving one of the headers and plant technicians took that compressor out of service for repair. While this compressor was out of service, the air headers were tied together per plant operating procedure. During the time the air headers were tied together, a valve on one of the headers failed, which degraded the station air supply for the plant and resulted in multiple generating units tripping
• In another example, power plant “B” with a common air header to both of its units experienced an overheating condition in the compressor room, causing two station air compressors to trip. The resulting drop in air pressure supply required the plant operators to manually trip both units due to load swings
• In a third example, at power plant “C” a loss of auxiliary cooling water caused all instrument air compressors at a generating station to trip. The resulting loss of instrument air supply caused both of the stations generators to run back and trip
LL20141203 Loss of Multiple Generators Due to Control Air Problems
RELIABILITY | ACCOUNTABILITY9
Lessons Learned:• Plant personnel should be mindful that, while operating in a single
header configuration, a problem with any part of the air system supply or the headers may result in a drop in control air and cause multiple units to trip
• The amount of time that power plants are in this configuration should be kept to a minimum to reduce the chance of this type of failure occurring
• When possible, individual air compressors should be fed from separate power supplies
• The installation of additional air compressors may be required to handle a significant loss of station air
• Procedures and checklists may also need to be updated or revised to address unforeseen low station air pressure conditions
LL20141203 Loss of Multiple Generators Due to Control Air Problems
RELIABILITY | ACCOUNTABILITY10
Links to Lessons Learned
• 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.
RELIABILITY | ACCOUNTABILITY11
ORCA Update
NERC Operating CommitteeDecember 9, 2014
Presentation 7.a
1
MISO – An Industry Leader in Reliability
• MISO’s focus throughout its history has been on improving reliability beyond industry accepted levels – and doing so while maximizing system efficiency– Congestion Management Process– Market-to-Market (M2M) Coordination Process– Wide area view, visualization and operating tools
• Had we not been successful in consistently achieving this objective we, as an organization whose ultimate responsibility is reliability, would not continue to exist and create value
• The addition of our South Region provided and opportunity to expand this efficient reliability to consumers more broadly
2
South Region expansion required that we work collaboratively with many entities to prepare…
• As some entities in and surrounding the region were unfamiliar with organized market operations MISO has worked to expand their understanding
• MISO conducted extensive outreach and education to alleviate uncertainty and address concerns– This included numerous meetings between MISO, TVA and Southern
Company to discuss how reliability would be maintained post-integration
3
…including the establishment of ORCA between MISO and the Joint Parties to support the expansion
• ORCA was put in place on December 19, 2013 to allow the Joint Parties to gain familiarity and experience with the expanded MISO BA operation – and specifically with increasing flow levels
• The ORCA was structured to be a temporary, short-term agreement, which contributed to MISO’s acceptance of it given its discriminatory treatment of flows from MISO customers
• The agreement established an initial artificial limit for MISO Dispatch flows of 2,000 MW, even though studies have shown the system can reliably accommodate over 3,000 MW of transfers
As assured, South entities have been reliably integrated and a year of successful operations has been logged
4
Overall TLRs in SERC declined significantly – by nearly 45% - between 2013 and 2014
MISO North MISO South PJM SERC SeRC TVA VACS SERC TotalTLRs
2013 (Q1-Q3) 60 188 18 0 62 6 3342014 (Q1-Q3) 23 26 0 5 106 26 186
0
50
100
150
200
SERC TLR Activity2013 vs. 2014 (Q1 - Q3)
5
0
200
400
600
800
1000
1200
0
20
40
60
80
100
120
Palmyra XF Montrose - Clinton Fairport - Osborn Volunteer - PhippsBend
All Other TVA FGs Total TVA FGs
Hour
s of T
LR
Num
ber o
f TLR
Eve
nts
2013 TLR Events 2014 TLR Events 2013 TLR Hours 2014 TLR Hours
While TVA TLRs have increased 65% year-over-year, driven primarily by increases on three flowgates…
The increase in total TVA TLRs (41) is attributable to the increase on three AECI flowgates (42)
6
…an analysis of the events finds that weather and outages were the causal factors – the integration has had minimal to no impact
• Palmyra 345/161kV Transformer (AECI)– Ongoing long-term outages supporting MVP upgrades in the region
have increased congestion in 2014; projects will help mitigate local congestion when completed
– Dispatch Flow Transfer Distribution Factor on Palmyra FGs averages ~0.7%, except during outages (since Palmyra – Sub T 345kV outage, TDF = ~ 2.69%)
• Montrose – Clinton 161kV Line (AECI)– TLRs occurred during extreme cold weather in early 2014– Dispatch Flow Transfer Distribution Factor on Montrose – Clinton FGs
averages ~0%• Fairport – Osborn 161kV Line (AECI)
– Increase driven by TLRs occurring during outage events– Dispatch Flow Transfer Distribution Factor on Fairport – Osborn FGs
averages ~1.3%, except during outages (during Overton 345kV outages, TDF = ~ 3.33%)
7
Varying Dispatch Flow levels during the TLR events is evidence of the lack of a relationship between the two
-2000-1500-1000
-5000
500100015002000
MIS
O D
ispa
tch
Flow
Dispatch Flow during Palmyra 345/161 2014 TLR Events
-2000-1500-1000
-5000
500100015002000
MIS
O D
ispa
tch
Flow
Dispatch Flow during Montrose – Clinton 2014 TLR Events
-2000-1500-1000
-5000
500100015002000
MIS
O D
ispa
tch
Flow
Dispatch Flow during 2014 TLR Events Fairport - Osborn 161kV
8
Even when agreed to exceedances of the 2,000 MW limit have occurred – like when MISO assisted PJM during the 2014 Polar Vortex – reliability has been maintained
Hourly ORCA Dispatch Flow
PJM EEA2 DeclarationPJM EEA1 Declaration
Hourly Net Scheduled Interchange (NSI) between MISO and PJM
9
However, agreement to progress beyond Phase 1 of ORCA has been elusive
• ORCA called for increasing levels of Dispatch Flow limits• Unfortunately non-reliability based concerns have prevented
progression beyond the first phase limit of 2,000 MW• To the extent that additional experience with increased flows is
desired, it can be achieved through alternative approaches to increasing the limit
10
The sunset of ORCA will not impact reliability, which will continue to be maintained just as it was in the pre-ORCA world
• Existing RC to RC (Reliability Coordinator) agreements and the reliability protocols put in place by NERC will sufficiently enable reliability in an equitable manner
• If other parties believe changes to those protocols are warranted MISO is certainly open to a broad discussion focused on industry-wide changes that could improve how the system is collectively planned and operated
• Under current protocols reliability would be achieved through:– RC’s perform next-day security analysis and develop mitigation plans as
needed– MISO commits generation on day-ahead basis to stay within its firm
transmission capabilities– Current day, non-firm, economic transfers managed comparably and
equitably via TLR as flows approach limits– Feedback loop adjusts day-ahead commitments to account for loop flows to
limit reoccurring TLRs (MISO does not start/ramp generation that it expects will be curtailed by TLR)
11
MISO remains committed to enhanced coordination with our neighbors that will result in improved reliability and efficiency along entity borders
• MISO has offered enhanced Joint Operating Agreements to the Joint Parties that would enable efficient reliability beyond industry accepted levels
• MISO has also expressed a willingness to explore a new short-term agreement that would begin at the termination of ORCA and allows for greater utilization of the system within its capabilities
• MISO will continue to participate in studies to assess future reliability; it is critical though that those studies include multiple scenarios given the uncertainty that exists today around future energy policy and its impact
Essential Reliability Services Status UpdateDecember 2014
Presentation 7.c
RELIABILITY | ACCOUNTABILITY2
ERSTF Activities
• Meeting held in Vancouver• Working meeting October 2014, Atlanta GA• ERSTF Concept Paper Posted OC and PC feedback incorporated and supported – THANK YOU! Final version posted online:
http://www.nerc.com/comm/Other/Pages/Essential-Reliability-Services-Task-Force-(ERSTF).aspx
• The Policy Subgroup completed a first draft (not final) working document from the Phase 2 efforts which was socialized to this committee on December 3, 2014. Draft ERSTF Measures Framework Report Phase II Deliverable Phase II
RELIABILITY | ACCOUNTABILITY3
• Subgroups identified nine possible Measures • Task Force recommended four move forward, the remaining
five need further evaluation Initial assessment of ERCOT pointed at a changing inertia trend Similarly, initial assessment of CAISO pointed to a change and need for
ramping capability Accordingly, the task force decided to further study various measures for
ramping capability needs and inertia.
October Meeting Outcome
RELIABILITY | ACCOUNTABILITY4
• The Task Force is seeking Endorsement of the document and approach “Draft ERSTF Measures
Framework Report Phase II Deliverable Phase II” The report tracks and provides the necessary level of technical detail
guidance for each of the Measures the Task Force is evaluating The report provides the status of the Measures – e.g. four Measures are
being recommended for OC and PC endorsement, the remaining five need further evaluation
The report is a ‘living’ document and won’t be ‘finalized’ until 2015
• Endorsement will result in the posting of document as Version 1• Endorsement will allow Task Force to progress forward and
work on the approach to gather data and information from industry for Measure 1, 2, 3 and 6.
Today- Endorsement from OC and PC
RELIABILITY | ACCOUNTABILITY5
• Measures 1 and 3 identify the parameters and data required to measure historical inertia at an Interconnection and BA level respectively.
• The historical data can then be used to project future trends
Task Force Recommends Measures 1 & 3
RELIABILITY | ACCOUNTABILITY6
• Measure 2 is extrapolated from Measure 1 and can be achieved for Interconnection level data
• This measure utilizes framework to calculate a Rate of Change of Frequency (RoCoF) for an interconnection. This measure is intended for planning horizon level.
Measure 2
RELIABILITY | ACCOUNTABILITY7
• Measure 6 identifies Ramping Capability Requirements at the Balancing Authority level. Provides both a historical and future (worst case) view for one and three
hour ramping capability requirements
Task Force Recommends Measure 6
RELIABILITY | ACCOUNTABILITY8
• Measures 4 & 5 are under being further evaluated by the Frequency Support Subgroup: Measure 4 will analyze frequency Nadir following a contingency event
under minimal system inertial scenario Measure 5 will explore the possibility of developing a real-time model for
operational purposes, including setting dynamic limits given a resource mix scenario
• Measures 7,8 & 9 are also under consideration by the ERSTF and further discussion will be conducted at December meeting. 7, 8 & 9 consider measuring static and dynamic reactive levels and voltage
performance
Task Force EvaluatingMeasures 4, 5, 7, 8 & 9
RELIABILITY | ACCOUNTABILITY9
• OC and PC endorsement on Phase II document and the Measures 1, 2, 3 and 6 Phase 2 document goal is to provide detailed guidance for each Measure Endorsement will allow Task Force to collect relevant data from different
entities and apply the framework modelo Use existing NERC data gathering processes (similar to ALR)o Always consider the size of data sample (all or subset) to minimize impact and
burden to industry Data gathering will allow the Task Force to conduct further evaluation of
the Measure’s and their necessity and applicability
Today- Endorsement from OC and PC
RELIABILITY | ACCOUNTABILITY10
• Next steps for the task force: Establish data collection and analyze 1, 2, 3 and 6 Measures Continue analyzing Measures 4, 5, 7, 8 & 9 Continue to update Phase 2 working document Commence draft for Final Report (June 2015) on Measures and
Methodology Phase 3 Planning
Next Steps
RELIABILITY | ACCOUNTABILITY11
Thank you to the Subject Matter Experts and Industry Leaders that have, and continue to, dedicate their time and expertise to this effort!
Thank You
RELIABILITY | ACCOUNTABILITY12
Eastern InterconnectionFrequency InitiativeTroy BlalockSouth Carolina Electric and GasVice Chairman, NERC RSNERC Operating CommitteeDecember 9-10, 2014
Presentation 7.i
RELIABILITY | ACCOUNTABILITY2
Preface:• Members of the NERC Resource Subcommittee, whom are
representatives of the Eastern Interconnection, are working with Balancing Authorities within the same interconnection on a voluntary basis to support an effort to improve frequency response.
• Frequency Response is defined as automatic and sustained change in the power consumption or output of a device such as generator that occurs within 5-20 seconds of and is in a direction to oppose a change in the Interconnection Frequency.
Eastern Interconnection Frequency Initiative
2
RELIABILITY | ACCOUNTABILITY3
The current initiative focus is on the existing generator fleet with respect to:1. completeness and accuracy of the data provided in the 2010 NERC Generator Survey, 2. to improve their frequency response capabilities and;3. for Balancing Authorities and/or Reliability Coordinators to installs tool(s) to monitor individual generator performance within their authority of control and communicate performance results to the individual generators
Eastern Interconnection Frequency Initiative
RELIABILITY | ACCOUNTABILITY4
2013 Eastern Interconnection Initiative Results: Dead Band Provided
Eastern Interconnection: Dead Band Setting
Provided?
Yes (2531 , 57.21%)
No (1893 , 42.79%)
2010 Generator Survey
No (173, 26%)
Yes (482, 74%)
Eastern Interconnection: Dead Band Setting Provided
2013 Generator Survey
Data does not include MISO, PJM, SPP
• For all individual generators (including nuclear) 100 MW or larger, BAs were requested to provide a completed generator survey of governor settings and related data.
4
RELIABILITY | ACCOUNTABILITY5
2013 Eastern Interconnection Initiative Results: Dead Band Setting
Dead Band Settings
0
20
40
60
80
100
120
140
160
180
0 mHz 2 mHz to 15mHz
15 mHz to 30mHz
30 mHz to 33mHz
36 mHz 50 mHz to 120mHz
120 mHz to 540mHz
Needs to be lowered
Note: Data does not included MISO, PJM, and SPP
Needs to be confirmed
RELIABILITY | ACCOUNTABILITY6
MISO Governor Settings Reported
None of these generators would contribute response for measured events
RELIABILITY | ACCOUNTABILITY7
GE Governor K3TN_DB
425 MW Coal Unit GE Mark V
Starts responding at 59.748 Hz vs. 59.964 Hz
MVA Fuel Type Dead Band Governor Type858 Bituminous Coal 252 GE Mark V858 Bituminous Coal 252 GE Mark V514 Bituminous Coal 252 GE MARK Vie395 Bituminous Coal 252 GE MARK Vie
342Subbituminous Coal 252 GE Mark V
342Subbituminous Coal 252 GE Mark VIe
265 Natural Gas 252 General Electric - Mark VI
7
RELIABILITY | ACCOUNTABILITY8
Variable Name
% Speed
RPM mHz Activation Conditions
KTN_ERR_DB0
0.25 9 150 Active during CV testing
KTN_ERR_DB1
0.025 0.9 15 Active when generator breaker is closed
KTN_ERR_DB2
0 0 0 Active when generator breaker is open
K3TN_DB 0.42 15.12 252 See below
GE Dead Bands Mark III-VI
RELIABILITY | ACCOUNTABILITY9
Secondary Controls
Dead band 36 mHzDroop 5%
Why lack of response?
In AGC mode, no frequency input into set point value.
175 MW GE7FA Mark VI Natural Gas Turbine
9
RELIABILITY | ACCOUNTABILITY10
• 2013 Data Reveals Many GOs do not know what their dead band value is Many dead bands exceed 36 mHzo GE MARK III- VI K3TN_DB dead band issue of setting 252 mHz
Many Generators have outer loop control when operating in AGC or Set Point Control that does not include frequency response.
Summary
RELIABILITY | ACCOUNTABILITY11
“Typical Lazy L” “Progress”
Eastern Interconnection Frequency Response
11
RELIABILITY | ACCOUNTABILITY12
NERC Alert
RELIABILITY | ACCOUNTABILITY13
RELIABILITY | ACCOUNTABILITY14
Performance Analysis Subcommittee UpdateMelinda Montgomery, Manager Transmission Planning, PAS ChairOperating Committee Meeting December 9-10, 2014
Presentation 7.r
RELIABILITY | ACCOUNTABILITY2
• Metric review ALR 1-5 Transmission System Voltage Profile ALR 2-3 Activation of Under Frequency Load Shedding ALR 6-11 Automatic AC Transmission Outages Initiated by Failed Protection
System Equipment ALR 6-12 Automatic AC Transmission Outages Initiated by Human Error ALR 6-13 Automatic AC Transmission outages Initiated by Failed AC
Substation Equipment ALR 6-14 Automatic AC Transmission Outages Initiated by Failed AC Circuit
Equipment ALR 6-15 Element Availability Percentage ALR CP-1 (Proposed Compliance Metric) Serious Risk Violations ALR CP-2 (Proposed Compliance Metric) Potential Violations with
Observable Reliability Impact
• 2015 State of Reliability schedule
Overview
RELIABILITY | ACCOUNTABILITY3
• ALR1-5 is Transmission System Voltage Profile• Formula is At select transmission system nodes (e.g., busses), record one-minute
average node (bus) voltage for positive sequence, phase-to-phase RMS (root-mean-square) value. Record the number of minutes the actual voltage level is outside a predetermined range around nominal.
• Recommend ALR 1-5 data collection be discontinued. This metric will be replaced with a metric to be developed by the Essential Reliability Services Task Force (ERSTF).
ALR 1-5 Recommendations
RELIABILITY | ACCOUNTABILITY4
• ALR2-3 is Activation of Under Frequency Load Shedding• Formula is Number of activation of UFLS by each region and total MW of load
interruption by each Region and NERC wide.
• Recommend ALR 2-3 be discontinued. To be replaced with a metric to be developed by the ERSTF.
ALR 2-3 Recommendations
RELIABILITY | ACCOUNTABILITY5
• Metrics require changes due to BES definition change• Changes proposed to Metric Description: Normalized count (on a per circuit basis) of Bulk Electric System 200kV and
above AC Transmission Element outages (i.e. TADS momentary and sustained Automatic Outages) that were initiated by the TADS cause code of Failed Protection System Equipment. Failed Protection System Equipment. This metric will use the TADS data and definition of Failed Protection System Equipment. Transmission Elements in this metric includes AC Circuits and Transformers.
• Changes proposed to Data Collection Interval and Roll Up: The TADS data provides the total number of automatic transmission
system outages and the number of outages initiated by Failed Protection System Equipment for Bulk Electric System elements.
ALR 6-11 Recommendations
RELIABILITY | ACCOUNTABILITY6
• Metrics require changes due to BES definition change• Changes proposed to Metric Description: Normalized count (on a per circuit basis) of Bulk Electric System 200kV and above
AC Transmission Element outages (i.e. TADS momentary and sustained Automatic Outages) that were initiated by the TADS cause code of Human Errors. This metric will use the TADS definition of Human Error, which states “Automatic Outages caused by any incorrect action traceable to employees and/or contractors for companies operating, maintaining, and/or providing assistance to the Transmission Owner will be identified and reported in this category. Also, any human failure or interpretation of standard industry practices and guidelines that cause an outage will be reported in this category.” Transmission Elements in this metric includes AC Circuits and Transformers.
• Changes proposed to Data Collection Interval and Roll Up: The TADS data provides the total number of automatic transmission system
outages and the number of outages initiated by Human Errors for Bulk Electric System elements.
ALR 6-12 Recommendations
RELIABILITY | ACCOUNTABILITY7
• Metrics require changes due to BES definition change• Changes proposed to Metric Description: Normalized count (on a per circuit basis) of Bulk Electric System 200kV and above
AC Transmission Element outages (i.e. TADS momentary and sustained Automatic Outages) that were initiated by the TADS cause code of fFailed AC sSubstationeEquipment. This metric will use the TADS definition of “Failed AC Substation Equipment”, which states “Automatic Outages caused by the failure of AC Substation; i.e., equipment “inside the substation fence” including Transformers and circuit breakers but excluding Protection System equipment. The TADS definition of “AC Substation” states “An AC Substation includes the circuit breakers and disconnect switches which define the boundaries of an AC Circuit, as well as other facilities such as surge arrestors, buses, transformers, wave traps, motorized devices, grounding switches, and shunt capacitors and reactors. Series compensation (capacitors and reactors) is part of the AC Substation if it is not part of the AC Circuit. See the explanation in the definition of “AC Circuit.” Protection System equipment is excluded.” Transmission Elements in this metric include AC Circuits and Transformers.
ALR 6-13 Recommendations
RELIABILITY | ACCOUNTABILITY8
• Metrics require changes due to BES definition change• Changes proposed to Metric Description: Normalized count (on a per 100 circuit-mile basis) of Bulk Electric System
200kV and above AC Transmission Element outages (i.e. TADS momentary and sustained Automatic Outages) that were initiated by the TADS cause code of fFailed AC cCircuit eEquipment. This metric will use the TADS definition of “Failed AC Circuit Equipment”, which states “Automatic Outages related to the failure of AC Circuit equipment, i.e., overhead or underground equipment ‘outside the substation fence.’ Refer to the TADS definition of “AC Circuit”, which states “A set of AC overhead or underground three-phase conductors that are bound by AC Substations. Radial circuits are AC Circuits.” Transmission Elements in this metric include AC Circuits and Transformers only.
ALR 6-14 Recommendations
RELIABILITY | ACCOUNTABILITY9
• Will need to be modified based on TADSWG Sunset Provision recommendation (later in agenda).
ALR 6-15 Status
RELIABILITY | ACCOUNTABILITY10
ALR CP-2 Proposal
• Impactful Violations and PVs by quarter• Should enable risk reduction using approaches proven in other
industries and fields of study Industrial safety Quality control and process improvement
• Some adjustment would occur as PVs progress through enforcement
• “Top 10” Requirements associated with observed impacts provide added value Information sharing on underlying causes and mitigation activities Starting point for development and evaluation of requirement-level
internal controls
11 RELIABILITY | ACCOUNTABILITY
ALR CP-2 Foundation
• At NERC Board meetings, Commissioner LaFleur notes she believes in the theory of the Accident Pyramid (larger events are prevented by continuously finding and rooting out small problems)
• We can build metrics and a risk management approach that mirrors effective utility safety programs
Fatalities
Injuries
Near Misses
Unsafe Acts
System Events
Moderate Impact
Minor Impact
No Impact PVs
Safety Model Compliance Parallel
12 RELIABILITY | ACCOUNTABILITY
ALR CP-2 Data Collection
• Capture the following with each log entry and Potential Violation (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
System Events
Moderate Impact
Minor Impact
No Impact PVs
RELIABILITY | ACCOUNTABILITY13
• Work has already begun• Draft due to PC/OC reviewers on April 8• Projected chapters 1 Key Findings 2 2014 Year in Review 3 SRI plus TADS, GADS, DADS data analysis summary 4 ALR Dashboard and specific ALR discussions as needed 5 New ALR-CP metrics, if available 6 EA Summary 7 Generation response to previous SOR Key Findings 8 Transmission response to previous SOR Key Findings 9 Distribution response to previous SOR Key Findings 10 SED
2015 SOR Schedule
RELIABILITY | ACCOUNTABILITY14
Southern Company Polar Vortex Experience
Presentation 7.p
Pre-event Preparations Winter Operations Drill - 12/04/13
• Annual System Alert drill to prepare for cold weather operations.
Friday - 01/03/14 • Temperature forecast for the following week
continues to drop.• Reviewed unit commitment plans.• Issued Conservative Operations Watch & Fleet
Advisory on Friday, January 3rd, for period of January 6th-8th.
Southern Company Polar Vortex Experience
January 5 – 7, 2014
0
10
20
30
40
50
60
20
30
40
501/
5/14
12:
00
1/6/
14 0
:00
1/6/
14 1
2:00
1/7/
14 0
:00
Tem
p
Load
(GW
)
Load Temp
January 7, 00:00 to 07:00• Over 7000 MW forced out/unavailable• Implemented ~1500 MWs Demand Side
Reductions• Peaked at 45,887 MW
Transmission Opportunities• System Alert Process• Demand Side/Interruptibles• Load Forecasting• Manual Load Shed• Balancing Area Tools
Polar Vortex Opportunities
Polar Vortex OpportunitiesGeneration Opportunities Key Points• Freeze Protection owners• Annual Training requirements• Maintenance Plan Oversight
• Operations Team performed Training, procedures, and tools
• Several opportunities to learn and improve• Better positioned for “next” event
Polar Vortex Opportunities
Questions
EIDSN Update
NERC Operating Committee MeetingDecember, 2014
Presentation 7.o
Overview
• Vendor Selection• Schedule• Questions
Page 2
Vendor Selection
• Board approved Vendor recommendations on September 8.
• Contracts Executed in November
• Sprint - Network Administration and Primary Backbone.
• AT&T – Secondary Backbone.Page 3
Schedule
• December 2014– Circuit Orders Placed– Implementation/Transition Plan Determined
• January 2015– Circuit Installation Begins
• May 2015– Circuit Installation Complete– Transition from NERCnet Complete
Page 4
Questions?
RRM Dashboard
Updated November 20, 2014
Presentation 7.g
RELIABILITY | ACCOUNTABILITY2
Event Counts
Event Category Count (Total) Count (2014) Comments
CAT 1 390 123
In 2014: 45 Three or more BPS facilities lost (1a);10 AESO Islanding (1b); 1 NB islanding (1b)5 BPS SPS/RAS Misoperation (1c) 8 Control Room evacuations (1f); 2 Generation lost (1g); 52 Partial EMS (1h)
CAT 2 134 21
2014:18 - EMS events (2b)1 – Volt Excursion (2c)1 – Unintended loss of load (2f)1 – IROL (2g)
CAT 3 15 1 Loss of 2,103 MW generation (2 Nuclear units)
(May 2014)
CAT 4 3 0SW Winter Weather (2011)SW Blackout (2011)Derecho (2012)
CAT 5 2 1 Hurricane Sandy (2012)Polar Vortex (2014)
Total CAT 1-5 Events 544 146
Non-Qualified Occurrences reported 2022 305
RELIABILITY | ACCOUNTABILITY3
Weather Driven Events
RELIABILITY | ACCOUNTABILITY4
Control Chart of Qualified Events
9 Cat 1h events
Process change: Started capturing Cat 1h events
RELIABILITY | ACCOUNTABILITY5
Control Chart of Cat 1 Events
Process change: Started capturing Cat 1h events
9 Cat 1h events
RELIABILITY | ACCOUNTABILITY6
Control Chart of Cat 2 Events
Process change: Started capturing Cat 1h events
RELIABILITY | ACCOUNTABILITY7
Control Chart for Cat 1 – 3 Events
Process change: Started capturing Cat 1h events
9 Cat 1h events
RELIABILITY | ACCOUNTABILITY8
Daily eSRI Trending
Slope of the line for the data for 2011-2013 = -0.00000765 (baseline)Slope of line with data from Jan-Nov 2014 added and re-evaluated = -0.00001334Difference (Current – Baseline) = -0.00000569 (slope is more negative)
RELIABILITY | ACCOUNTABILITY9
Compliance Self-Assessment by Region (Overall)
RELIABILITY | ACCOUNTABILITY10
NERC Cause Analysis Training
FRCC MRO NPCC RFC SERC SPP TRE WECC Other Totals
Trained ERO Staff 12 7 5 39 15 13 12 13 48 164
Trained Industry 64 64 31 224 69 41 45 175 32 745
Trained Trainers (TT)
5 1* 23 2 15 46
Trained by TT
43 43
Total 76 70 36 263 84 54 57 188 80 909
RELIABILITY | ACCOUNTABILITY11
2010 2011 2012 2013 2014 Total
FRCC 0 0 0 1 3 4
MRO 0 2 0 0 1 3
NERC 23 1 0 0 2 26
NPCC 0 5 2 5 4 16
RF 0 3 1 3 4 11
SERC 0 1 0 1 1 3
SPP 0 0 2 0 2 4
TRE 0 5 8 1 3 17
WECC 0 5 5 3 1 14
Total 23 22 18 14 18 98
Lessons Learned Metrics
RELIABILITY | ACCOUNTABILITY12
NERC Alerts Issued
RELIABILITY | ACCOUNTABILITY13
James Merlo, PhDDirector, Reliability Risk Management404-446-9750 office | 404-387-5249 [email protected]
RELIABILITY | ACCOUNTABILITY14
Cat 3 and Higher Events (2010-2012)
Year Category Event
2010 Cat 3 4 unit trip (2122MW) 2 generator loss (1436MW)
2011 Cat 3 Spring tornados 1000kVDC intertie & generation loss (2427MW)Virginia earthquake Halloween Snow Storm
2011 Cat 4 SW Cold WeatherSW Blackout
2012 Cat 3 12 generators lost ( 2060MW) 3 generator loss (2453MW)
2012 Cat 4 Derecho: Wind storms
2012 Cat 5 Hurricane Sandy in NE
RELIABILITY | ACCOUNTABILITY15
Cat 3 and Higher Events (2013)
Year Category Event
2013 Cat 3 • Nine (9) generation units, totaling 2700MW, tripped as a result of maintenance problems
• Loss of 2 Nuclear plants and 345kV Switchyard
• Fire and smoke resulted in faults on the PDCI, leading to proper reactive switching actions, and proper dropping a net of 2,895 MW of generation in the Pacific Northwest
• Loss of one 735 kV line due to forest fire, followed by 3 more 735kV lines from “protection malfunction”; lost multiple generation units and >2000MW
• Loss of three 735 kV lines due to forest fire; lost multiple generation units and load
• Flooding in the Greater Toronto Area (GTA) triggered protection operations. This removed twenty-five 230kV circuits and resulted in a loss of supply to a significant portion of the 115 kV system supplying load to the GTA. Approximately 3800MW of load was lost
RELIABILITY | ACCOUNTABILITY16
Cat 3 and Higher Events (2014)
Year Category Event
2014 Cat 3 Loss of 2,103 MW generation (2 Nuclear units)
Cat 4 and 5 Polar Vortex
RELIABILITY | ACCOUNTABILITY17
• Two Lessons Learned were Published in February 2014: LL20140201 -Identify Relay Programming Errors to Prevent Unintended
Operations LL20140202 - A Generating Station Ground Mat Problem Led to the Trip of
Two Generating Units (2000 MW)
• Two Lessons Learned were Published in March 2014: LL20140301 - Turbine Combustor Lean Blowout on Large-Frame
Combustion Turbines LL20140302 - Verification of Alternating Current Quantities during
Protection System Commissioning
• Three Lessons Learned were Published in May 2014: LL20140501 - High AC Voltage can Lead to Remote Terminal Unit Failures LL20140502 - Circuit Breaker Modification Leads to Inadvertent Trips LL20140503 - Improved Contractor Oversight Needed
2014 Lessons Learned
RELIABILITY | ACCOUNTABILITY18
2014 Lessons Learned
• Four Lessons Learned were Published in June 2014: LL20140601 - Generation Relaying - Underfrequency Protection
Coordination LL20140602 - Generation Relaying - Overexcitation LL20140603 - Verify That Actions Called for in Operating Guides Can Be
Implemented Within Required Time Frames LL20140604 - Loss of SCADA Due to Memory Resources Being Fully Utilized
• Two Lessons Learned were Published in August 2014: LL20140801 - Load-Shedding Plans for Localized Events LL20140802 - Loss of EMS Monitoring and Control Functionality for More
Than 30 Minutes
RELIABILITY | ACCOUNTABILITY19
2014 Lessons Learned
• Three Lessons Learned were Published in September 2014: LL20140901 Communications Redundant Network Interface Cards on EMS
Systems LL20140902 Communications Loss of EMS/Dispatch Workstation
Functionality due to NTP Time Synchronization Device Misconfiguration LL20140903 Relaying and Protection Systems System Protection Review
Prior to Disabling Protective Relays
• Three Lessons Learned were Published in December 2014 LL20141201 Control System Network Switch Failure LL20141202 Bus Differential Power Supply Failure LL20141203 Loss of Multiple Generators Due to Control Air Problems
Integration of Variable Generation Task ForceUpdate on Summary and Recommendations of 12 Tasks Report
Noha Abdel-Karim, Senior Engineer, NERCOperating Committee Meeting December 9-10, 2014
Presentation 7.q
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
Summary Report - Overview
• 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 summarized and refreshed each of the task’s recommendations and conclusions
• Objective: Summarizes and refreshes the 12 tasks 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.
RELIABILITY | ACCOUNTABILITY4
• Work progress with IVGTF leadership to develop a transition plan on recommendations. Coordination with working groups and NERC Standard department. Incorporating into the summary report.
• 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
IVGTF Final ReportWork In Progress
RELIABILITY | ACCOUNTABILITY5
Next Steps:• OC/PC review the Final Summary report incorporating IVGTF
transition plan, which delegates the effort to the NERC LTRA, Special Assessments, and to the Essential Reliability Services Task Force (ERSTF).
• Report Target Release: March, 2015.• NERC staff recommends to 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 ERSTF. • 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
RELIABILITY | ACCOUNTABILITY6
Energy Infrastructure Modeling and Analysis Division: Research Status Report
December 9 - 10, 2014
NERC Operating Committee
Emmanuel Taylor – Electrical Engineer
Presentation 7.m
2 2
Presentation Outline
1. Background on OE and EIMA
2. Review of research projects
This presentation will cover the following topics:
3 3
Core Purpose of OE
OE drives grid modernization by improving energy system:
4 4
Energy Infrastructure Modeling and Analysis
EIMA addresses dynamics, complexity, and uncertainty, through:
to improve energy infrastructure decision making.
5 5
EIMA Has Two R&D Programs
Transmission Reliability Advanced Grid Modeling
6 6
Two research projects highlighted:
Focus of this Research Update
Project Title PI Institution
Optimization, Numerical Computation, and Reliability Assessment for Interdependent Energy Infrastructures
Victor M. Zavala, Ph.D.
Argonne National Laboratory
Spectral Coherence Analysis for Oscillation Detection for Alarming and Daily Summary
Frank Tuffner, Ph.D.
Pacific Northwest National Laboratory
7 7
Coupled, Interdependent Infrastructure
Principal Investigator:
Victor M. Zavala, Ph.D.
Cong Liu, Ph.D.
Mohammad Shahidehpour, Ph.D.
Research Objective:
Applying optimization, numerical computation, and reliability assessment to the problem of integrated natural gas and electric power scheduling.
Institution:
Argonne National Laboratory
Project Timeline:
August 2010 – September 2014
Significance:
Co-optimize the economics of dispatching electrical generation resources, and compressors for natural gas distribution.
8 8
Coupled, Interdependent Infrastructure
A co-optimization routine is run, to minimize unit commitment costs in the electrical system and compressor energy costs in the gas network.
C. Liu, M. Shahidehpour, J. Wang; “Coordinated scheduling of electricity and natural gas infrastructures with a transient model for natural gas flow”; Chaos, 2011
9 9
Coupled, Interdependent Infrastructure
Co-optimization was performed in a study utilizing the IEEE 118 bus test case: Example contained 12 combined cycle plants, subject to gas system constraints.
C. Liu, M. Shahidehpour, J. Wang; “Coordinated scheduling of electricity and natural gas infrastructures with a transient model for natural gas flow”; Chaos, 2011
10 10
Coupled, Interdependent Infrastructure
Case One: Steady State System Models Case Two: Transient Natural Gas Model, Low Line Pack Case Three: Transient Gas Model, High Line Pack
C. Liu, M. Shahidehpour, J. Wang; “Coordinated scheduling of electricity and natural gas infrastructures with a transient model for natural gas flow”; Chaos, 2011
11 11
Coupled, Interdependent Infrastructure
Past Accomplishments:
• Developed mathematical framework for describing transient characteristics of gas network
• Demonstrated the tradeoffs from coordinating schedules for gas and electricity dispatch
Next Steps:
• Project completed its scope
• This topic remains a departmental focus
12 12
Spectral Analysis
Principle Investigator:
Frank Tuffner, Ph.D.
Spectral Coherence Analysis Tool
Research Objective:
Utilize spectral analysis methods to investigate underlying oscillations in the power system and provide a means to detect them.
Institution:
Pacific Northwest National Laboratory
Project Timeline:
March 2014 – December 2014
Significance:
Diagnose grid issues and increase the overall understanding of power system dynamics. This work will provide alarms to operators, notifying them of oscillations that may be of concern.
13 13
Spectral Analysis
The Spectral Coherence Analysis Tool is able to detect sustained frequency oscillations that would otherwise be missed using time domain analysis.
Tuffner, Frank; “Spectral Analysis Baselining”,;DOE/OE Transmission Reliability Program Review; June 3-4, 2013; Washington, DC
14 14
Spectral Analysis
Past Accomplishments:
• Spectral coherence algorithm implemented in MATLAB
• Algorithm deployed within BPA testing environment
• Successfully utilized to detect wind farm oscillations and probing tests
Spectral Coherence Analysis Tool
Work in Progress:
• Working with grid operators to:
• Define appropriate alarm threshold levels
• Improving software through
• Daily events summary
• Last hour’s events list
• Improve algorithm stability for real-time implementation
15 15
The feedback of the OC on the value of these projects is appreciated.
Feedback and Insights
16 16
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.
ACSETF Report
Michael Lombardi, Manager of System Studies, NPCCOC / PC Meetings – December 2014
Presentation 7.l
2 RELIABILITY | ACCOUNTABILITY
Background
• 2013 State of Reliability Key Finding 5: AC Substation Equipment Failures are a Second Significant Contributor to Disturbance Events and Automatic Transmission Outage Severity
• The AC Substation Equipment Task Force (ACSETF) convened to: Analyze failed AC substation equipment failure data in event analysis data
and other applicable reports Identify the key factors that exacerbate the impact of AC substation
equipment failure to the BES Identify specific items, actions and develop recommendations to improve
industry performance
3 RELIABILITY | ACCOUNTABILITY
Review Status
• Excellent feedback from OC/PC reviewers Improved report with much more clarification and linkages between the
topics Extensive comments process; all comments addressed by ACSETF and
NERC staff
• Many thanks go to: Jerry Rust (OC) Alan Bern (OC) Todd Lucas (OC) Russell Schussler (PC) Steve Huber (PC) Gary Brownfield (PC) Melinda Montgomery (PS)
4 RELIABILITY | ACCOUNTABILITY
Activities
• Data Collection, various sources Events Analysis TADS Supplemental Survey WECC Substation Work Group (SSWG) Industry Reports
• Data Analysis• Identification of observation/recommendation• OC/PC review – comments/feedback incorporated• Requesting Approval/Endorsement in December OC/PC meeting
5 RELIABILITY | ACCOUNTABILITY
Observation & Recommendation
• TADS Data / Transmission Severity Calculation O: Incomplete picture of failed AC substation equipment impact on
reliability.o Outage duration not consideredo Transformer outages not includedo Treats the impact of all lines within a voltage class as identicalo Data collection lacks consistency for cause analysis
R: Incorporate data from other sources and analyze the impact on BES reliability. (NERC)
R: Consider improvements in transmission severity calculation. (NERC) R: Investigate a consistent method for data collection using industry
guidelines. (NERC / Entities)
6 RELIABILITY | ACCOUNTABILITY
Observation & Recommendation
• Bus Configurations / Circuit Breakers O: The failure of a circuit breaker to operate properly increases the
probability that additional BPS elements will also be forced out-of-service, increasing the transmission outage severity of the incident.
R: Evaluate the failure rate of circuit breakers and consider the impact of bus configuration on AC transmission circuit outages (NERC).
O: Bus configuration is the primary determinant of the impact of breaker failure on transmission outage severity.
R: Evaluate the impact of breaker failures on system performance when choosing bus configurations for new installations or modifying existing substations. (Entities)
7 RELIABILITY | ACCOUNTABILITY
Observation & Recommendation
• NERC Reliability Standard TPL-001-4 — Transmission System Planning Performance Requirements(Enforcement Data 1/1/2015) O: Standard will address some of the impact of bus design and breaker
failure, i.e.: will addresses multiple contingencies which are often created from substation equipment failures.
R: Monitor industry implementation of TPL-001-4 to verify that planning studies include multiple contingencies to evaluate the effect of substation equipment failures. (NERC)
8 RELIABILITY | ACCOUNTABILITY
Observation & Recommendation
• Bushings O: Bushings as part of a large piece of substation equipment could cause
system reliability vulnerabilities to persist with insufficient research or industry wide notification.
R: High voltage equipment bushings should be categorized and treated as a completely separate piece of substation equipment. (NERC)
9 RELIABILITY | ACCOUNTABILITY
Observation & Recommendation
• ALR 6-13, Automatic AC Transmission Outages Initiated by Failed AC Substation Equipment O: The analysis of ALR6-13 indicates that the outage trend of Failed AC
substation equipment is declining and immediate intervention is not warranted at this time.
R: Continue to monitor and trend this metric. (NERC)
10 RELIABILITY | ACCOUNTABILITY
Participation, Data Sharing and Best Practices
• Use optimal lubrication practices for each circuit breaker• Define a process for the distribution, tracking and analysis of
manufacturer issued service advisories• Investigate, analyze, and report all BES substation equipment
failures per the applicable IEEE Guideline• Participate in industry groups such as NATF, and EEI, etc. to
share investigation results• Include results in NERC Event Analysis investigations• Proactive replacement of equipment where industry experience
identifies a generic problem in a specific device.
11 RELIABILITY | ACCOUNTABILITY
Conclusion
• Though, it is not possible to eliminate all substation equipment failures, it is important that entities design, build and maintain substation configurations and equipment to minimize adverse effects (i.e., severity) associated with potential AC substation equipment failures.
• Determination of the bulk power system reliability implications and transmission outage severity can provide a basis for system enhancement.
12 RELIABILITY | ACCOUNTABILITY
Questions and Answers
*Some related backgrounds slides are included in the remaining part of presentation
Thank You!
13 RELIABILITY | ACCOUNTABILITY
• AC Substation Equipment Failure and Transmission Outage Severity Inherent in AC substation equipment failure is an increased probability
that additional BPS elements will also be forced out of service, potentially increasing Transmission Outage Severity.
The function and arrangement of substation equipment often increases the number of transmission lines forced out of service when substation equipment fails. By design, substation equipment is always located in close proximity to TADS transmission line terminals
• Circuit breakers are the leading equipment failure due to: Frequency of operation Number of circuit breaker in service
Relationship with Transmission Severity
14 RELIABILITY | ACCOUNTABILITY
AC Substation Equipment Failures by Equipment Type
39%
28%
10%
5%3% 2% 2%
3%
8% Circuit Breaker
Transformer
Bushing
Instrument Transformer
Switch
Capacitor
Circuit Switcher
Arrester
All Other
15 RELIABILITY | ACCOUNTABILITY
• Three common bus configurations are: Straight or radial Buso This configuration results in the highest transmission outage severity among the
three configuration as a result failed circuit breaker. Ring Buso This configuration dramatically reduces the impact on transmission outage
severity resulting from a failed circuit breaker Breaker and a half Buso This configuration further reduces the impact on transmission outage severity
resulting from a failed circuit breaker.
• From survey data, It is worth noting that 67% of the circuit breaker initiated outages were located at substations with a single bus-single breaker bus configuration ( chart on next slide)
Substation configuration
16 RELIABILITY | ACCOUNTABILITY
Circuit Breaker Failure by Bus Configurations (Survey Results)
13%
3%
12%
5%
67%
Breaker-and-a-Half
Other
Ring Bus
Sectionalized Bus
Single Bus