Joint Session Operating/Planning/Critical Infrastructure Protection Committee Conference Call and Webinar. June 4, 2013

Transcription

1 Joint Session Operating/Planning/Critical Infrastructure Protection Committee Conference Call and Webinar June 4, 2013

2 New NERC Website Mike Moon, Senior Director of Reliability Risk Management Joint Session OC/PC/CIPC June 4, 2013

3 New NERC Website Launched May 9, 2013 Migrating documents Archived documents Notify NERC of problems ; CC department admin; o CID, Jenny Gomez Jenny.Gomez@nerc.net o RAPA, Michelle Marx Michelle.Marx@nerc.net o RRM, Sandy Shiflett Sandy.Shiflett@nerc.net 2

4 Posting Guidelines qwe Reliability and Security Guidelines 3

5 Mike Moon Senior Director Reliability Risk Management office cell 4

6 Update on the Arizona-Southern California Outages Report Causes and Recommendations Mike Moon, Senior Director Reliability Risk Management June 4, 2013

7 ERO Activity Focus 27 Recommendations; grouped A Next-Day and Real-Time Operating Issues o 1-4 next-day planning o situational awareness o 18 Interconnection Reliability Operating Limit o protection systems o 27 angular separation B Longer-Term and Seasonal Planning Issues o 5-8 seasonal planning o 9-10 planning processes 2

8 Regional Activities Significant work Staff Stakeholder committees RCs and TOPS Activities in-depth, long term Sharing data Improving modeling and coordination Improving processes and procedures Adding capabilities 3

9 NERC Committee Activities Incorporating learning from events into processes Operating Committee Review of real time tools in monitoring Planning Committee System protection and control Two reports support standards projects Standards Committee Real-time reliability monitoring and analysis capabilities project 4

10 Mike Moon Senior Director Reliability Risk Management office cell 5

11 Standardizing a Template for Reliability/Security Guidelines Mike Moon, Senior Director of Reliability Risk Management Joint Session OC/PC/CIPC June 4, 2013

12 Reliability Guideline Name of Guideline Month XX, 2013 Applicability (as necessary depending on issue): Introduction and Purpose: It is in the public interest for NERC to develop guidelines that are useful for maintaining or enhancing the reliability of the bulk power system (BPS). The Technical Committees of NERC; Operating Committee (OC), Planning Committee (PC) and the Critical Infrastructure Protection Committee (CIPC) per their charters 1 are authorized by the NERC Board of Trustees (Board) to develop Reliability (OC and PC) and Security Guidelines (CIPC). These guidelines establish a voluntary code of practice on a particular topic for consideration and use by BPS users, owners, and operators. These guidelines are coordinated by the technical committees and include the collective experience, expertise and judgment of the industry. The objective of this reliability guideline is to distribute key practices and information on specific issues critical to maintaining the highest levels of BPS reliability. Reliability guidelines are not to be used to provide binding norms or create parameters by which compliance to standards is monitored or enforced. While the incorporation of guideline practices are strictly voluntary, reviewing, revising, or developing a program using these practices is highly encouraged to promote and achieve the highest levels of reliability for the BPS. Responsibilities: A. NERC as the FERC certified ERO 2 is responsible for the reliability of the BPS and has a suite of tools to accomplish this responsibility, including but not limited to: lessons learned, reliability and security guidelines, assessments and reports, the Event Analysis program the Compliance Monitoring and Enforcement Program and mandatory reliability standards. B. Each entity as registered on the NERC compliance registry is responsible and accountable for maintaining reliability and compliance with the mandatory standards to maintain the reliability of their portions of the BPS. C. Entities should review this guideline in detail in conjunction with the periodic review of their internal processes and procedures and make any needed changes to their proecedures based on their system design configuration and business practices. Background:

13 Text on background information that prompted this Guideline to be drafted. May include references and information from previous reports or analysis. Guideline Details: Text on the specific details of the Guideline Related Documents and Links: List Documents related to this Guideline and applicable links Revision History: Date Version Number Reason/Comments XX/XX/XXXX 1.0 Initial Version name of Guideline Reliability Guideline: Name of Guideline 2

14 Example Attachment (if needed for more technical detail) Elements of a Reliability Guideline Attachment (sample name) A. Organization and Planning 1) Assign specific personnel responsible for implementing guideline 2) Executive Management support 3) Perform periodic drills B. Work Management System 1) Ensure adequate annual preventive work orders exist as needed. 2) Ensure all engineered modifications and construction activities are performed as needed. C. Critical Infrastructure Protection 1) Ensure all critical site specific problem areas have adequate protection to ensure operability. D. Staffing 1) Consideration of enhanced staffing (24x7) during. 2) Arrangements for transportation as needed. 3) Support and appropriate staffing from 3 rd parties. E. Communications 1) Ensure appropriate communication protocols are followed 2) Identify a back-up communication option in case the primary system is not working F. Special Operations Instructions 1) Loss of power Reliability Guideline: Name of Guideline 3

15 Protection System Misoperations Task Force Targeted and Actionable Steps to Reduce Protection System Misoperations Phil Tatro, Senior Engineer, NERC OC/PC/CIPC Joint Webinar, June 4, 2013

16 Objectives Provide insight into protection system misoperations Identified as a significant reliability issue Lessen the disturbance event severity caused by misoperations Disseminate actionable information to prevent and reduce misoperations 2

17 Protection System Misoperations Task Force (PSMTF) Analysis Reviewed historical (pre-2011) Regional Entity misoperations Analyzed 1,500+ misoperations from January 1, 2011 to April 1, 2012 submitted in NERC misoperations template Focused on top 3 misoperation causes: Incorrect settings/logic/design Relay failure/malfunction Communication failures Classified misoperations in top 3 misoperation causes by sub causes Based on the analysis of top issues, developed suggestions for improvement to reduce top misoperation areas Recommended data monitoring and data improvements 3

18 Misoperations by Cause Code NERC-wide Misoperations by Cause Code (Jan 1, 2011 April 1, 2012) Communication failures, 396, 17% AC system, 193, 8% As-left personnel error, 201, 9% DC system, 112, 5% Relay failures / malfunctions, 465, 20% Unknown / unexplainable, 273, 12% Incorrect setting / logic / design errors, 628, 28% Other, 11, 1% 4

19 Incorrect Settings/Logic/Design Errors This category includes misoperations due to engineering errors by the protection system owner. These include: Setting errors; Errors in documentation; And errors in application. Examples include: Uncoordinated settings; Incorrect schematics; Or multiple CT grounds in the design. 5

20 Incorrect Settings/Logic/Design Errors by Second Level Cause 350 Incorrect Settings/Logic/Design Error Misoperations by Second Level Cause Misoperations Relay Settings Protective Function Relay Settings Logic 66 Wiring Design Prints 26 6 Relay Misapplication Other Second Level Cause 75 Insufficient Information 24 Wrong Code 8 Not a misop 6

21 Relay Settings Protective Function Misoperations by Third Level Cause 160 Relay Settings Protective Function Misoperations by Third Level Cause 140 Protective Function Misoperations Protection Element Setting Error Improper Relay Coordination Timing Over Reaching Zone 1 or IOC Elements Improper Coordination of DCB Scheme Trip and Block Elements Modeling Errors Third Level Cause 7

22 Relay Settings Logic Misoperations by Third Level Cause 100 Relay Settings Logic Misoperations by Third Level Cause 90 Relay Settings - Logic Misoperations General Setting Logic Error Direction Settings Issues Coordination Timers Set Improperly Winding Improper Use of Echo Compensation Issues Logic Firmware Issues Third Level Cause 8

23 Relay Failures/Malfunctions This category includes misoperations due to improper operation of the relays themselves. These may be due to: Component failures; Physical damage to a device; Firmware problems; Or manufacturer errors. Examples would include Misoperations caused by: Changes in relay characteristic due to capacitor aging; Misfiring thyristors; Damage due to water from a leaking roof; Relay power supply failure; Or internal wiring/logic error. Failures of auxiliary tripping relays fall under this category. 9

24 Relay Failure/Malfunction Misoperations by Second Level Cause and Relay Technology Relay Failure/Malfunction Misoperations Relay Failure/Malfunction Misoperations by Second Level Cause and Relay Technology Other Solid State Microprocessor Electromechanical 10 Second Level Cause

25 Communication Failures This category includes misoperations due to failures in the communication systems associated with protection schemes inclusive of transmitters and receivers. Examples would include misoperations caused by: Loss of carrier; Spurious transfer trips associated with noise; Telco errors resulting in malperformance of communications over leased lines; Loss of fiber optic communication equipment; Or microwave problems associated with weather conditions. 11

26 Communication Failure Misoperations by Second Level Cause and Category Misoperations Communication Failure Misoperations by Second Level Cause and Category Communication Interface Failure (Modulator) Communication Medium 5 61 Station Signal Path Failure Incorrect Logic Settings Issued - Communications Human Error (Misapplication in Field) - Communications Relay wiring/connection Second Level Cause Multiple Second Level Causes Insufficient Information 9 Wrong Code Not a misoperation Unnecessary Trip other than fault Unnecessary Trip during fault Slow Trip Failure to Trip

27 Suggestions for Improvement Proper Application of Relay Elements Settings Errors Microprocessor-based Relay Firmware Application of Power Line Carrier Communication Aided Protection Performance Monitoring and Data Improvements 13

28 Proper Application of Relay Elements Applications requiring coordination of functionally different relay elements should be avoided. If these applications cannot be avoided, the coordination should be studied and tested thoroughly. This type of coordination is virtually always problematic, and is the cause of numerous misoperations reported in the study period. Some examples to avoid include: Coordinating distance elements with overcurrent elements Directional overcurrent elements at opposite line terminals that use different directional polarization methods, particularly in the same pilot scheme Coordinating overcurrent elements that use different measurement methods, such as phase vs. residual ground vs. negative-sequence current measurement 14

29 Settings Errors Misoperations due to setting errors can potentially be reduced. Techniques that could be used to reduce the application of incorrect settings include: Peer reviews Increased training More extensive fault studies Standard templates for setting standard schemes using complex relays Periodic review of existing settings when there is a change in system topography The IEEE Power System Relaying Subcommittee, IEEE PSRC, published a working group report to provide additional technical guidance for protective relay setting quality control. 15

30 Microprocessor-based Relay Firmware Entities should evaluate the need to apply updated firmware. While many firmware updates may not be critical to the relay protection functions, updated firmware that corrects critical protection functions should be given priority. IEEE Standard C37.231, IEEE Recommended Practice for Microprocessor-Based Protection Equipment Firmware Control Discusses various aspects of firmware version control and provides guidelines for the effective administration of firmware-related issues. 16

31 Application of Power Line Carrier Communication Aided Protection Momentary signal loss (holes) sometimes caused by protective spark gaps firing during the fault. Spark gaps need to be inspected for build up and for the proper, manufacturer-required gap. Use of a carrier hole override timer on digital systems may be used as a means to reduce misoperations. While carrier hole timers can provide added security to DCB schemes, they can mask carrier system setting or component deficiencies. The decision to apply this logic should be weighed carefully. Modern check-back equipment is helpful to detect the failure to perform a carrier test. Provides better communication scheme condition indication than many older check-back test schemes Alternatively, frequency shift keying (FSK) carrier can be used with microprocessor based Resources for Power Line Carrier Communication Aided Protection A Reliable Power-Line Carrier-based Relay System, Miriam P. Sanders, P.E. (Quanta Technology, LLC). Investigation and Analysis into the Mis-Operation due to Carrier Holes, John J. Meinardi, Florida Power & Light Co., and Miriam P. Sanders, PE AMETEK Power Instruments, Copyright Special Considerations in Applying Power Line Carrier for Protective Relaying, IEEE Power Systems Relaying Committee Special Paper. 17

32 Performance Monitoring Detailed misoperation analysis should be continued on at least an annual basis by the respective Protection System Subcommittees within the Regions. This analysis will be forwarded to the NERC SPCS and NERC Performance Analysis Subcommittee for trending and metrics reporting. Adequate Level of Reliability Metric (ALR4-1) to monitor misoperations ns.aspx 18

33 Data Improvements Misoperations with Insufficient Information High percentage (over 24%) of misoperations did not have enough information to subcause Improved data submission by entities would improve accuracy Consistency in Reporting Improved Event Description field instructions to guide entities on needed information Entities should verify with neighbors when tie-line misoperations occur to avoid double counting Reporting Multiple Occurrences Template Enhancements 19

34 2012 Event Analysis NERC Event Analysis 2012 o 116 Category 1-5 Events o 42 Events with Misoperations Events with Misops 36% Events without Misops Events without Misops 64% Events with Misops 20

35 2012 EA Misoperations Causes Aligned to PSMTF Categories 2012 EA Misops by Cause (aligned to PSMTF codes) failed relay 17% communications 15% ct circuit 10% other 10% incorrect protection setting/logic/design errors 46% control system 0% bad ct 2% 21

36 NERC EA 2012 Misops by Cause NERC EA 2012 Misops by cause incorrect protection setting failed relay communications ct circuit other incorrect logic wiring/design error bad ct control system 22

37 Preliminary 2013 Events Preliminary 2013 Event Analysis as of 4/30/ events o 10 Misoperations 23

38 One of High Priority Risk Issues from RISC PSMTF Report Approved by PC on April 8, Targeted suggestions for improvement to reduce misoperations NERC Industry Webinar May 7, 2013 Request training modules for specifics of targeted solutions Share industry example of excellences State of Reliability Report Released May 15, 2013 NERC/Industry Actions Protection System Misoperations are a Significant Contributor to Disturbance Events and Automatic Transmission Outage Severity o Largest positive correlation with 2012 automatic transmission outage severity o Statistically significant, highest relative risk Training Modules for Each Primary Cause - Completion by July 2013 On-Going Performance Monitoring (ALR4-1) spx

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40 2013 Special Reliability Assessment: Accommodating an Increased Dependence on Natural Gas for Electric Power Recommendations and Follow-on Activities for OC/PC

41 Key Findings and Recommendations Planning Short and Long-Term Risk-based and probabilistic analysis (3 Layer) Cross-industry information and data sharing Robust understanding of dual-fuel capabilities Integration into Long-Term Reliability Assessment. Operations Season-Ahead through Real-Time Preparations and response plans Coordinated operational planning and information sharing Harmonized procedures for extreme conditions 2

42 Next Steps Prioritization RISC involvement and guidance OC/PC consideration of RISC input Incorporate into committee work plan Project Scoping and Work Plan Development Identify tasks and deliverables Determine coordination opportunities with natural gas industry 3

43 Recommendations for Committees Planning Committee Promote advanced modeling and analysis approaches. NERC recommends the Three Layer approach or similar advanced probabilistic techniques. Incorporate natural gas fuel availability or natural gas fired generation availability into the NERC Long Term Reliability Assessment and Seasonal Reliability Assessments. Enhance the NERC Generator Availability Data System (GADS) to increase the effectiveness of trending gas fired generator outages and causes related to fuel issues. Improve Generator Owner procedures and methods to maintain fuel switching capabilities. Work jointly with the natural gas industry to identify data requirements that can be used for electric reliability analysis. 4

44 Recommendations for Committees Operating Committee System operators should re examine inter-industry communication protocols that apply during periods of stress NERC should leverage its stakeholder groups to identify best practices in areas currently most vulnerable to gas dependency risks and taking immediate actions for improvement, such as New England. Such an effort could lead to insights for enhanced operator training and table top exercises. Joint industry drills or table top exercises with the key players of both gas, electric, and various state commissions would foster enhanced coordination and harmonize cross industry issues, response plans, and mitigation measures. 5

45 John Moura Director of Reliability Assessment North American Electric Reliability Corporation office 6

46 NERC BES Implementation - Overview and Summary Carter B. Edge, Director, Coordinated Activities Regional Entity Management Group June 4, 2013

47 Summary of BES Discussion Order Nos. 773 and 773-A Implementing the Bulk Electric System (BES) definition Notifications of Inclusions and Exclusions Exception requests Implementation Timeline Motion for extension of time BES Phase II Project Final Thoughts 2

48 Order Nos. 773 and 773-A Approved 100 kv BES Bright Line and related NERC rules Affirmed FERC Authority over Local Distribution determinations Affirmed July 1, 2013 implementation date Directed that Exclusions E1 and E3 do not apply to BES generator tie-lines (i.e., interconnection facilities) that connect generators identified in Inclusion I2. Directed a change to E3 related to local networks. Affirmed directives are included in BES Phase II Project 3

49 BES Implementation BES Definition Application Inclusions Exclusions Exceptions Technical Review Panel NERC Technical Review Final Decision Known Issues E1/E3 Tie Lines NERC Guidance Pause self-determined exclusions Removal of 100 kv Reference Applicability of Standards Phase II Finalization Self-determined under E3 Relative to specific submittals Target EOY 2013 Address directives 4

50 BES Notifications & Exceptions Tool Project Timeline Deployment 1 Notifications; submittal of requests; regional recommendations Deployment 2 NERC decisions; Appeals; Reporting The NERC Motion for a one year extension of the effective date now pending is not expected to affect these project dates. 5

51 BES Phase II BES Phase II Project Scope Address issues raised in Phase 1 Address FERC Directives o o Modify Exclusion E3 under 100 kv provision Implement Exclusions E1 and E3 to include generator tie lines consistent with Inclusion I2 Refine I4 consistent with Inclusion I2 Comment, ballot, and BOT approval by late

52 June 2013 Training workshops and webinars for entities July 2013 Deployment 1 for BES Notification and Exceptions Tool Implementation Timeline Will not be available for use if motion to extend is granted October 2013 Expanded BES Notification and Exceptions Tool functionality December 2013 Target completion for BES Phase II July 2014 Effective date for the BES Definition and ROP Exception Protocol pending decision by FERC 7

53 Final BES Thoughts Consistent implementation across ERO Enterprise Prepared to implement the Phase 1 definition on July 1, 2013 as planned BES tool to manage processing of Notifications and Exception Requests across ERO Enterprise NERC training and orientation for Entities BES Phase II Project to address FERC Directives and Phase I comments NERC to issue transition guidance Motion for one year extension pending decision guidance provided depending on FERC action Alignment of BES definition and ROP exceptions 8

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55 Reliability Standards for GMD FERC Order 779 Mark Olson, Standards Developer Joint Technical Committees Webinar June 4, 2013

56 Presentation Topics Overview of FERC Order 779 Launching the Standards Development Project 2

57 Order 779 FERC Order directs NERC to file standards that address geomagnetic disturbance (GMD) impacts in two stages: Operating Procedures (file by January 2014) Vulnerability assessments and mitigation plans (file by January 2015) Define benchmark GMD events in Stage 2 Order responds to NOPR comments with clarified directives and timelines better aligned with GMD Task Force project 3

58 Stage 1: Operating Procedures Standard(s) that require entities to implement Operating Procedures to mitigate the effects of GMDs Requirements should allow procedures to be tailored based on entity-specific factors Geography, geology, and system topology Consider coordination of procedures across Regions 4

59 Stage 2: Assessments and Mitigation Standard(s) that require entities to assess the impact of benchmark GMD events on the bulk power system Benchmark GMD events must be defined and technically justified Involve Planning Coordinators for a wide-area view 5

60 Stage 2: Assessments and Mitigation Entities must develop and implement strategies to address potential impacts Could include specifications, isolating equipment, blocking, etc. Cannot be limited to Operating Procedures No plan is required when assessment indicates no potential impacts 6

61 Stage 2: Assessments and Mitigation NERC is directed to propose implementation plan Considerations: Availability of validated tools, models, and data Prioritizing implementation 7

62 Launching the Standards Project GMD Task Force has provided input for Standards Authorization Request (SAR) Strong technical experience to define project scope Provides an open and transparent forum Standards Committee will initiate formal standards development process when SAR is accepted 8

63 Mark Olson Standards Developer North American Electric Reliability Corporation office cell 9