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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


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


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


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


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


• 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


• 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



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



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.

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

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SERC TLR Activity2013 vs. 2014 (Q1 - Q3)

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Palmyra XF Montrose - Clinton Fairport - Osborn Volunteer - PhippsBend

All Other TVA FGs Total TVA FGs

Hour

s of T

LR

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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

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tch

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Dispatch Flow during Palmyra 345/161 2014 TLR Events

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-5000

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Dispatch Flow during Montrose – Clinton 2014 TLR Events

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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


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

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


• 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


• 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


• 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


• 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


• 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


• 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


• 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


• 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


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

Eastern InterconnectionFrequency InitiativeTroy BlalockSouth Carolina Electric and GasVice Chairman, NERC RSNERC Operating CommitteeDecember 9-10, 2014

Presentation 7.i


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


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


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


2013 Eastern Interconnection Initiative Results: Dead Band Setting

Dead Band Settings

0

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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


MISO Governor Settings Reported

None of these generators would contribute response for measured events


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


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


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


• 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


“Typical Lazy L” “Progress”

Eastern Interconnection Frequency Response

11


NERC Alert

Performance Analysis Subcommittee UpdateMelinda Montgomery, Manager Transmission Planning, PAS ChairOperating Committee Meeting December 9-10, 2014

Presentation 7.r


• 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


• 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


• 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.



• 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.



• 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.



• 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.



• 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.



• Will need to be modified based on TADSWG Sunset Provision recommendation (later in agenda).

ALR 6-15 Status


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


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


• 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

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

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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


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


Weather Driven Events


Control Chart of Qualified Events

9 Cat 1h events

Process change: Started capturing Cat 1h events


Control Chart of Cat 1 Events


9 Cat 1h events


Control Chart of Cat 2 Events



Control Chart for Cat 1 – 3 Events


9 Cat 1h events


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)


Compliance Self-Assessment by Region (Overall)


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


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


NERC Alerts Issued


James Merlo, PhDDirector, Reliability Risk Management404-446-9750 office | 404-387-5249 [email protected]

mailto:[email protected]


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


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


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


• 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



• 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



• 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


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


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.


• 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


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

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


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


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.


10 10


Case One: Steady State System Models Case Two: Transient Natural Gas Model, Low Line Pack Case Three: Transient Gas Model, High Line Pack


11 11


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


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


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)


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


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)



• 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)



• 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)



• 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)



• 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)


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.


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.


Questions and Answers

*Some related backgrounds slides are included in the remaining part of presentation

Thank You!


• 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


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


• 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


Circuit Breaker Failure by Bus Configurations (Survey Results)

13%

3%

12%

5%

67%

Breaker-and-a-Half

Other

Ring Bus

Sectionalized Bus

Single Bus

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