1. DEC System Voltage Planning - June 2018
Brian Moss, P.E., Lead Engineer, Transmission Planning Carolinas

2. DEC System Voltage Planning
Nuclear LOCA Voltage Studies (February)
Identifies future nuclear switchyard voltage deficiencies by performing LOCA simulation coupled with contingency analysis on system planning models
Determines minimum nuclear switchyard voltage limits, used to create generator voltage schedules and the TCC’s SCADA/RTCA alarm setpoints for the current year
Annual System Voltage Screening (Spring)
Identifies future voltage deficiencies by performing contingency analysis on system planning models
Annual System Voltage Analysis (Fall)
Identifies existing voltage deficiencies by reviewing the past year’s system voltage performance using PI data

3. DEC System Voltage Planning
Annual Transmission Capacitor Optimization (Spring or Fall)
Identifies optimal sites for capacitor placement to mitigate voltage deficiencies
Annual System Voltage Optimization (Fall)
Identifies transmission transformer tap setting and switched capacitor control setting adjustments to improve system voltage performance
Seasonal System Voltage Optimization (Spring, Summer, Fall, Winter)
Creates “Generator Voltage Schedules” to provide efficient utilization of system generator voltage support, while maintaining transmission system voltage guidelines and minimum nuclear switchyard voltage limits
Completed and issued to Generators at least 30 days prior to implementation date around the start of each season

4. DEC Nuclear LOCA Studies
Nuclear Generation Inputs (January)
Latest minimum grid voltage requirements, as well as shutdown and LOCA auxiliary loads for each unit
Normal, Pre-LOCA Base Cases
Latest summer peak and valley models
Sister Unit Off-Line, Pre-LOCA Base Cases
Dispatch variations of normal, pre-LOCA base cases
Outage non-LOCA unit at the nuclear station being evaluated
System redispatched to replace outaged unit and serve its shutdown auxiliary load

5. DEC Nuclear LOCA Studies
Pre-LOCA Contingencies
Pre-LOCA, post-contingency scenario solved to a new steady-state with all equipment (capacitors and transformer taps) allowed to adjust per their control settings
Generator
Largest Generating Unit on a Voltage Level at Each Generating Station
Transmission Line
44, 100, 230, and 500 kV Lines with only the Worst-Case Line Outaged for Parallel, Double-Circuit Lines
Transformer
100/44, 115/100, 161/66, 230/44, 230/100, 230/100/44, 230/161, and 500/230 kV Transformers
Shunt (Capacitors and Reactors)
44, 66, 100, 161, 230, and 500 kV
Capacitors and Reactors

6. DEC Nuclear LOCA Studies
LOCA Event
Simulate the initiation of a LOCA event on each pre-LOCA, post-contingency scenario
LOCA unit is outaged and LOCA auxiliary load is applied
Energy is imported from off-system to replace outaged unit and serve its LOCA auxiliary load
In order to estimate the switchyard voltage immediately following the LOCA event, transformer taps and capacitors are prevented from adjusting in the solution due to their long (30+ seconds) response times
Post-LOCA Voltage Evaluation
Determine the “LOCA Voltage Drop” (post-LOCA minus pre-LOCA, post-contingency nuclear switchyard voltage)
Post-LOCA voltages are only supported by the pre-LOCA, post-contingency capacitor MVAr support and the generator MVAR output of all remaining on-line units adjusting to maintain their generator voltage schedules in response to the LOCA event

7. DEC Nuclear LOCA Studies
Pre-Contingency Voltage Limits
Equal to minimum grid voltage requirement plus the worst-case (maximum) “LOCA Voltage Drop”
Real-time nuclear switchyard voltage required to maintain minimum grid voltage requirement in the event of the worst-case, pre-LOCA contingency followed by the initiation of a LOCA event
Generator Voltage Schedule Creation
Maintains minimum nuclear switchyard voltage limits equal to the pre-contingency voltage limits plus 2 kV
Additional 2 kV provides an added margin of system voltage support to the system above the required pre-contingency voltage limits

8. DEC Generator Voltage Schedules and Reactive Support
Generator Voltage Schedules (GVSs) in DEC
Largest Generators, Solar PV, and SVC
Switchyard Voltage
Generator Bus Voltage
Reactive Operating Schedule
Seasonal Schedules
Spring, Summer, Fall, Winter
Weekday Peak
Weekday Off-Peak
Weekend All Hours
Plant operators are expected to follow schedules 24/7 unless directed by the System Operating Center (SOC)

9. DEC Generator Voltage Schedules and Reactive Support
Schedule Creation in DEC
System voltage optimization using PSSE Optimal Power Flow (OPF)
Reduced (75%) Generator MVAR capability
Minimize system losses
Transmission System Voltage Guidelines
Nuclear LOCA switchyard and generator bus voltage requirements
Net Duke MVAR Interchange held at 0 to not rely on off-system MVAR support
Merchant (IPP) MVAR support requirements
Pre-Optimization Generator Voltage Schedule (GVS) Cases

10. DEC Generator Voltage Schedules and Reactive Support
Pre-Optimization GVS Cases (continued)
Latest summer peak, winter peak, or valley models
Add transmission projects installed and in-service for the majority of the season
Capacitors (including portables)
Transformers (including in-service system spares)
Transmission lines (including significant outages)
Generator maintenance outage schedule
Outage generators which are scheduled to be off-line for maintenance during the majority of the season
Typical dispatch with reduced (75%) generator MVAr capability
Provides a margin of additional MVAr capability not required to support the provided generator voltage schedules under typical conditions
Allows generators to follow the provided generator voltage schedules under varying system conditions
Firm, planned transactions

11. DEC Generator Voltage Schedules and Reactive Support
Optimal Power Flow (OPF) Solution
Objectives
Minimize active (MW) and reactive (MVAR) power losses
Constraints
Power balance equation
Transmission System Voltage Guidelines
Minimum nuclear switchyard voltage limits
Nuclear generator bus voltage limits
Important 100 kV bus voltage limits
Duke MVAr interface flow constraint
▪ Prevent schedules from relying on off-system MVAr import (0 MVAr net interchange)
Generator voltage limits
Merchant (IPP) MVAr support requirements

12. DEC Generator Voltage Schedules and Reactive Support
Optimal Power Flow (OPF) Solution (continued)
Transformer tap settings are fixed
Tap settings are optimized in “Annual System Voltage Optimization” and would not be adjusted seasonally
Controls
Generator voltage schedules (MVAr output)
Capacitors (MVAr voltage support)
Generator voltage schedules, Beckerdite SVC voltage setpoint, and reactors’ status are extracted from the optimized cases and provided to the SOC, TCC, and the generation operators as a guide for maintaining optimal system performance under typical seasonal Peak, Off-Peak, and Weekend conditions

13. DEC Generator Voltage Schedules and Reactive Support

14. DEC Generator Voltage Schedules and Reactive Support

15. DEC Generator Voltage Schedules and Reactive Support

16. DEC Generator Voltage Schedules and Reactive Support
If system conditions prevent MVA limited units from operating within the GVS upper and lower bounds, the unit may need to reduce MW output to GCC (or below as directed by the SOC) to comply with PF bound requirements.
All units may operate above GCC as long as system conditions allow them to operate within GVS upper and lower bounds.

17. DEC Generator Reactive Support Requirements
New Generator Voltage Support - Facility Connection Requirements (FCR)

18. DEC Reactive Capability Study
Identify the GSU tap setting that maximizes MVAR output capability to support the transmission system across wide ranges of switchyard and generator bus voltages
Used to optimize GSU Tap Settings to improve ability to support GVSs
Used in FS and SIS to determine if Generator can provide sufficient VAR support to the Transmission System

19. DEC Reactive Capability Study