NERC Event Analysis Update Webinar. Hassan Hamdar Chair, Event Analysis Subcommittee October 20, 2016

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1 NERC Event Analysis Update Webinar Hassan Hamdar Chair, Event Analysis Subcommittee October 20, 2016

2 Webinar Agenda ERO Event Analysis Process Update Lesson Learned Presentation from Entity ERO Lessons Learned Program Update 2 RELIABILITY ACCOUNTABILITY

3 ERO Event Analysis Process Update 3 RELIABILITY ACCOUNTABILITY

4 Event Analysis Process Update New draft posted for industry comment Version 3.1 Three main revisions Category 1g was revised to increase the upper threshold from 1,399 MWs to 1,999 MWs Category 2a was revised to align with COM and use of Interpersonal Communication capability Category 3a was revised to align all interconnection to a loss of 2,000 MWs or higher 4 RELIABILITY ACCOUNTABILITY

5 Category 1g and 3a Initial request to revise the categories was driven by Texas Regional Entity The request was reviewed and discussed by the Event Analysis Subcommittee (EAS) EAS agreed with the revision and the justification proposed by TRE TRE was asked to document the justification (available on the EA Program webpage) EAS received approval from the NERC Operating Committee to post the draft for a 45 day comment period (due by November 14, 2016) 5 RELIABILITY ACCOUNTABILITY

6 How to find the document Go to Program Areas & Departments > Reliability Risk Management > EA Program m/ea/pages/ea- Program.aspx 6 RELIABILITY ACCOUNTABILITY

7 Lesson Learned Presentation from Entity Maxime Nadeau Manager, System Control Operations and Scheduling Hydro Québec TransÉnergie 7 RELIABILITY ACCOUNTABILITY

8 NERC Lesson Learned Published December 29, RELIABILITY ACCOUNTABILITY

9 Management and monitoring of an SOL and IROL exceedances leading to an unrequired manual load shedding

10 HQT Main Transmission System Large generation complex located in the province northern area. 45,717 MW of installed capacity including 3,255 MW of wind generation. More than 90% is hydro generation. Around 50% of the load is in the southern part of the System. Winter peak is 175% of the summer peak. Historical peak load is 39,240 MW in ,224 MW of export capacity, mostly HVDC inter-ties. Bay JAMES BAY (15,000 MW) United States CHURCHILL FALLS (5,600 MW) New MANIC-OUTARDES (8,100 MW) 300 MW and more power plants 735 kv Substations 735 kv Lines Series compensation ± 450 kv DC Lines 10

11 Event summary During the morning peak, the Transmission System Operator ordered the de-energization of a shunt reactor at La Vérendrye substation (XL9) connected to a high voltage transmission line (L7016) for voltage control. During the operation, a fault occurred in the shunt reactor breaker causing the trip of the high voltage transmission line. Two IROL exceedances resulted. 11

12 Event Summary 12

13 Event Summary 13

14 Emergency Control Actions The System Operators (Transmission, Balancing, and Interchange) then took emergency operation control actions to restore the interface flows below the IROLs, such as: Starting gas turbines (400 MW); Curtailment of interchange transactions (1 000 MW); Emergency energy imports (1 000 MW); Regional (South) voltage reduction; 14

15 Emergency Control Actions 15

16 What the SO Saw on the Display 16

17 Load Shedding After 23 minutes, the interface flows was back under the IROL but still above the SOL. However, the System Operator - Transmission was still thinking he was exceeding the IROL being confused from his interpretation of the displays. Thus, 28 minutes after the event, the System Operator Transmission initiated MW of manual load shedding to restore system within IROL in 30 minutes or less. 37 minutes after the event, the line 7016 was put back in service and all the load was restored 35 minutes after it was shed. 17

18 Load Shedding 18

19 Similar Event on December 4,

20 Corrective Actions Analyze all the EMS monitoring tools to determine if SOL and IROL are clearly differentiated. Two issues were found: The SOL/IROL exceedance timer display was misleading; The System Operators were managing emergency situations with a static control actions list in which the operator had to identify by himself the control actions to apply. Thus, the following corrective actions were put in place: Upgrade the current timer display to make it more ergonomic and make sure that IROL and SOL are clearly differentiated; Create a new tool for System Operators (Transmission and Balancing) that would help them quickly select the required control actions according to the type of exceedance (SOL or IROL). 20

21 New Control Room Timer Display 21

22 SO Would Now See One Minute After the Line Trip 22

23 What the SO Would Now See After 23 Minutes 23

24 Limit Exceedance Management Tool Objectives: Provide real-time accurate situation awareness Centralize required mitigating emergency control actions Provide a follow-up on deployed actions Characteristics: Executed every minute by the Reserve Monitor Embedded in the EMS Dynamic throughout the event management Usable in test mode to do contingency analysis 24

25 New Limit Exceedance Management Tool 25

26 New Limit Exceedance Management Tool Messages that warn if it is an IROL or SOL exceedance Linear programming model manages multiple exceedances simultaneously Operator can exclude actions if deployment delay of that action exceeds his need for the current emergency situation Color coded and blinking to attract attention on important messages Messages that warn when Emergency Transmission Limits need to be implemented When Emergency Transmission Limits applied, recalculation of the solution 26

27 What the SO Would See 27

28 Lessons Learned Adequately differentiate the SOL and IROL limits in the EMS displays and the control room timer display for SOL/IROL exceedances. Improve System Operators simulation type training to add more stressful conditions in order to enhance their situational awareness and response during emergency operations. Review on a regular basis the System Operators understanding of the SOL and IROL limits and the emergency operation control actions permitted. 28

29 FYI NERC OC Reliability Guidelines 29 RELIABILITY ACCOUNTABILITY

30 Draft Reliability Guidelines Posted Draft NERC Operating Committee Reliability Guidelines Posted for Comment 30 Inadvertent Interchange Integrating Reporting ACE with the NERC Reliability Standards Situational Awareness for the System Operator Comment Period ends November 14, 2016 Go to > Committees > Operating Committee > Reliability Guidelines (on right side) Pages/Reliability-Guidelines.aspx RELIABILITY ACCOUNTABILITY

31 Situational Awareness for the SO Objective: To provide information on situational awareness and its applicability to real-time operation of the BES Provides global recognition of the importance for SOs to maintain situational awareness while operating the BES Meant to assist (TOP), Balancing Authorities (BA), Reliability Coordinators (RC), Generator Operators (GOP) to use with the primary goal of supporting BES reliability 31 RELIABILITY ACCOUNTABILITY

32 ERO Lessons Learned Program Update 32 RELIABILITY ACCOUNTABILITY

33 2015/2016 Event Count Event Category Count (Total) Count (2015/2016) Comments CAT /115 In 2015/2016: 37/47 Three or more BPS facilities lost (1a); 6/0 Islanding (1b); 6/3 BPS SPS/RAS Misoperation (1c); 1/0 Volt Red (1d); 7/0 Control Room evacuations (1f); 0/1 Loss of MW gen (ERCOT) (1g); 69/64 Partial EMS (1h) CAT /4 In 2015/2016: 16/0- EMS events (2b); 1/1 LOOP (2d); 4/3 Loss of >300MW Firm Load (2f) CAT /2 In 2015/2016: 1/2 Loss of > 1400MW of generation (3a) CAT 4 3 0/0 SW Winter Weather (2011) SW Blackout (2011) Derecho (2012) CAT 5 2 0/0 Hurricane Sandy (2012) Polar Vortex (2014) Total CAT 1-5 Events /121 Non-Qualified Occurrences reported / RELIABILITY ACCOUNTABILITY

34 Lessons Learned Metrics Published Lessons Learned By Year 34 RELIABILITY ACCOUNTABILITY

35 Category of Lessons Learned Published to Date 7 NERC lessons learned published to date in Relaying and Protection Systems 5 Communications 16 NERC lesson learned published in Relaying and Protection Systems 7- Communications 1- Transmission Facilities 2- Generation Facilities 2- Bulk-Power System Operations 35 RELIABILITY ACCOUNTABILITY

36 Lesson Learned Review Process Draft submitted Regional EA staff review/cleanup NERC EA staff review/cleanup NERC EAS initial review and recommendation to pursue or not NERC EAS sets small team to review with entity if available and willing NERC EAS final review and approval to post NERC Technical writing review 36 RELIABILITY ACCOUNTABILITY

37 Lessons Learned Input Methods ERO Event Analysis Process reports Major Disturbances Minor occurrences (or events that do not qualify for EA) Good outcomes that have information worthy of passing along Near miss (or near hit) Automatic Voltage Regulator Example Events not in North America 37 RELIABILITY ACCOUNTABILITY

38 Lessons Learned Feedback 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. A link is provided in the PDF version of each Lesson Learned. 38 RELIABILITY ACCOUNTABILITY

39 Access Lessons Learned Go to Program Areas & Departments > Reliability Risk Management > Event Analysis > Lessons Learned 39 RELIABILITY ACCOUNTABILITY

40 Contact Information Hassan Hamdar Chair, Event Analysis Subcommittee Jule Tate NERC Associate Director, Event Analysis General NERC Event Analysis Mailbox 40 RELIABILITY ACCOUNTABILITY

41 For more Information please contact: (via ) 41 RELIABILITY ACCOUNTABILITY