TOP/IRO Standards. RC Users Group January 21, Vic Howell Manager, Operations Engineering Support

Transcription

1 TOP/IRO Standards RC Users Group January 21, 2016 Vic Howell Manager, Operations Engineering Support Saad Malik Manager, Real-Time Operations Engineering

2 New/Revised TOP & IRO Standards November 19, 2015, FERC Order 817 Approves changes to TOP & IRO standards Accepts NERC s recommendation for the NERC Project : SOL Drafting Team to address clarity and consistency of SOLs and IROLs 2

3 General Changes 3 Fewer in number, simpler, cleaner, less prescriptive, more streamlined Alignment with new COM (effective 7/1/2016): no more Reliability Directive, replaced with Operating Instruction Authority who can issue Operating Instructions, who must comply with them SOL exceedance is a shared responsibility between TOPs and RCs NERC SOL White Paper

4 Major Change Highlights for RCs IRO-017-1: Outage Coordination R1. Each Reliability Coordinator shall develop, implement, and maintain an outage coordination process for generation and Transmission outages within its Reliability Coordinator Area. The outage coordination process shall: 1.1. Identify applicable roles and reporting responsibilities including: Development and communication of outage schedules Assignment of coordination responsibilities for outage schedules between Transmission Operator(s) and Balancing Authority(s) Specify outage submission timing requirements Define the process to evaluate the impact of Transmission and generation outages within its Wide Area Define the process to coordinate the resolution of identified outage conflicts with its Transmission Operators and Balancing Authorities, and other Reliability Coordinators. 4

5 Major Change Highlights for BAs and TOPs New TOP Purpose: To ensure that the Transmission Operator and Balancing Authority have data needed to fulfill their operational and planning responsibilities TOPs and BAs have documented data specifications Mirrors IRO for RCs 5

6 Major Change Highlights for BAs IRO R2. Perform the functions specified in its RC s outage coordination process TOP R4. Have an Operating Plan(s) for the next-day TOP R5. Notify entities identified in the Operating Plan(s) to their role in those plan(s) TOP R7. Provide its Operating Plan(s) for next-day operations to its RC 6

7 Major Change Highlights for TOPs 7 Prior to same-day and real-time: IRO R2. Perform the functions specified in its RC s outage coordination process TOP R1. Have an Operational Planning Analysis (OPA) to identify SOL exceedances TOP R2. Have Operating Plan(s) to address potential SOL exceedances identified in the OPA TOP R3. Notify entities identified in the Operating Plan(s) to their role in those plan(s) TOP R6. Provide its Operating Plan(s) for next-day operations to its RC

8 Major Change Highlights for TOPs Real-time: TOP R13. Ensure that a Real-time Assessment (RTA) is performed at least once every 30 minutes TOP R14. Initiate its Operating Plan to mitigate a SOL exceedance identified as part of its Real-time monitoring or RTA 8

9 Revised Definitions Operational Planning Analysis (OPA) Current Revised 9 An analysis of the expected system conditions for the next day s operation. (That analysis may be performed either a day ahead or as much as 12 months ahead.) Expected system conditions include things such as load forecast(s), generation output levels, Interchange, and known system constraints (transmission facility outages, generator outages, equipment limitations, etc.). An evaluation of projected system conditions to assess anticipated (pre-contingency) and potential (post-contingency) conditions for next-day operations. The evaluation shall reflect applicable inputs including, but not limited to, load forecasts; generation output levels; Interchange; known Protection System and Special Protection System status or degradation; Transmission outages; generator outages; Facility Ratings; and identified phase angle and equipment limitations. (Operational Planning Analysis may be provided through internal systems or through third-party services.)

10 Revised Definitions Real-time Assessment (RTA) Current Revised An examination of existing and expected system conditions, conducted by collecting and reviewing immediately available data. An evaluation of system conditions using Realtime data to assess existing (pre-contingency) and potential (post-contingency) operating conditions. The assessment shall reflect applicable inputs including, but not limited to: load, generation output levels, known Protection System and Special Protection System status or degradation, Transmission outages, generator outages, Interchange, Facility Ratings, and identified phase angle and equipment limitations. (Real-time Assessment may be provided through internal systems or through third-party services.) 10

11 Perform RTA every 30 minutes Typically this is: o SE o RTCA Variety of solutions can be considered to meet entity RTA obligations Peak s SE, RTCA, and study tools are offered to TOPs and BAs to help meet RTA functional needs 11

12 Perform RTA every 30 minutes (Contd.) Peak s tools can serve as back-up to entity s RTA during TOP s primary tool outage to meet 30 minute requirement 12 o Enhanced Curtailment Calculator (ECC) o Peak potentially performing backup role Use of Peak s Hosted Advanced Applications o Real-time analysis and monitoring of SOLs and IROLs o Outage Studies o Access to Peak Displays o Awareness of wide-area system topology changes

13 Challenges with RAS modeling in RTA A very large number of schemes Coordination of newly added schemes and automatic actions Correct modeling information (logic diagrams, documentation, etc.) Operator training Awareness of arming in real-time? Awareness of reliability issues with RAS due to changing system conditions Transient phenomena based RAS schemes 13

14 IRO Peak Implementation Heavy focus on new IRO-017-1: Outage Coordination TOPs, BAs, and RC need to be compliant with IRO by April 1, 2017 Broad stakeholder team Small development team Peak COS survey 14

15 Outage Coordination Project Milestones Milestone Outage Coordination Process Outline developed Post initial draft of Outage Coordination Process for stakeholder comment Date Completed 6/17/ st round Stakeholder comments due 7/15/2016 Post 2 nd draft of Outage Coordination Process for stakeholder comment 8/12/ nd round Stakeholder comments due 9/2/2016 Post final Outage Coordination Process 10/3/2016 Process implementation date 2/7/2017 IRO mandatory and compliance in effect 4/1/

16 Questions?