1. Raul E. Perez-Guerrero Advanced Technology
DER Impact Assessment
Raul E. Perez-Guerrero
Advanced Technology

2. Project Goals
Identify potential impacts of high penetration of DERs from a steady state and dynamics perspective.
Additional objectives include:
System behavior during faulted conditions
Slow voltage recovery due to induced faults (FIDVR)
Revision of existing modeling practices and protection settings
Generation displacement effects.
Explore system limits during stressed system conditions (e.g. Peak Load and/or Max PV).
Southern California Edison

3. Case Studies Case studies are based on 2021 topology.
Conditions of interest are limited to those in which significant DER (PV) will be present in the system (7 am to 6 pm).
Two conditions:
Peak: Load is at maximum output
Off-Peak: DER is at maximum output
An off-peak load condition resembling 8/16/2016 event was also produced and used as the off-peak case.
Southern California Edison

4. Case Studies Details SCE Case Year 2026 2021 8/16/2016 Pre-Event
SCE
Case Year
2026
2021
8/16/2016
Pre-Event
8/16/2016-Based
2021 Mod
Case Condition
Summer Peak
Off-Peak Load
Total Generation
15,618.4
13,110
6,586.9
11,068.2
10,791.1
Total Load
23,034.5
23,305.1
10,652.3
15,881.8
14,611.4
Total Losses
471.2
352.5
138.2
427.4
235.8
Net Interchange
-7,887.3
-9,558.4
-5,188.7
-4,056.2
Path 26
-3,980.5
-232.6
-1,566.5
-146.8
Pacific DC Intertie
-1,372.3
-730.6
-912.3
Palo Verde – Devers
-2,330.4
-982.0
-2,175.0
-1,543.4
Lugo - Victorville
-1,370.5
-527.2
-1,035.4
-681.2
Southern California Edison

5. Contingencies
Initial simulations performed over all N-1 contingencies at Lugo 500 kV (3ph).
Final set of simulations expanded contingencies to:
Lugo 500 & 230 kV (3ph, SLG, DLG)
Mira Loma 500 & 230 kV (3ph, SLG, DLG)
Rancho Vista 500 & 230 kV (3ph, SLG, DLG)
Serrano 500 & 230 kV (3ph, SLG, DLG)
Valley 500 kV (3ph, SLG, DLG)
Southern California Edison

6. DER Modeling Utility-Scale Threshold: REGC Model
Composite Load Model
CMPLDW
Utility-Scale Threshold: REGC Model
Industrial
Commercial
Utility
Distributed Energy Resources
PVD1 Model
Residential Rooftop PV
BTM Generation
Southern California Edison

7. Modeling of Distributed PV generation
Residential-Scale:
Smaller generators (e.g. residential rooftop solar, behind the meter installation).
PVD1 model.
Active Power control.
Utility-Scale:
Industrial and commercial (e.g. rooftop solar PV installations, utility-scale PV plants connected to the distribution system).
REGC_A/REEC_B model.
Volt-var control
Model normally reserved for large-scale generation, but used for purposes of modeling additional controls within the PV facility.
Southern California Edison

8. Dynamic Modeling Example
Commercial Dynamic Model
regc_a “BUSNAME " "DG" : #9 mvab=65.25 "lvplsw" 1. "rrpwr" 10.0 "brkpt" 0.9 "zerox" 0.4 "lvpl1" "vtmax" 1.2 "lvpnt1" 0.8 "lvpnt0" 0.4 "qmin" -1.3 "accel" 0.7 "tg" 0.02 "tfltr" 0.02 "iqrmax" 999. "iqrmin" "xe" 0.
reec_b “BUSNAME " "DG" : #9 "mvab" 0. "vdip" -99. "vup" 99. "trv" 0.2 "dbd1" -0.5 "dbd2" 0.5 "kqv" 0. "iqh1" 1.5 "iql1" -1.5 "vref0" 0. "tp" 0.5 "qmax" 0.4 "qmin" -0.4 "vmax" 1.1 "vmin" 0.9 "kqp" 0.0 "kqi" 0.1 "kvp" 0.1 "kvi" "tiq" 0.2 "dpmax" 999. "dpmin" "pmax" 1. "pmin" 0. "imax" 1.3 "tpord" 0.4 "pfflag" 0. "vflag" 1. "qflag" 1. "pqflag" 0.
repc_a “BUSNAME " "DG" : #9 "mvab" 0. "tfltr" 0.2 "kp" 18. "ki" 5. "tft" 0. "tfv" 0.15 "refflg" 1. "vfrz" - 1. "rc" 0. "xc" 0. "kc" 0. "vcmpflg" 1. "emax" 999. "emin" "dbd" 0. "qmax" 0.44 "qmin" "kpg" 0.1 "kig" 0.5 "tp" "fdbd1" 0. "fdbd2" 0. "femax" 999. "femin" "pmax" 999. "pmin" "tlag" 0.1 "ddn" 20. "dup" 0.0 "frqflg" 0.
lhvrt “BUSNAME " "DG" : #9 "vref" 1.00 "dvtrp1" "dvtrp2" -0.3 "dvtrp3" "dvtrp4" 0.1 "dvtrp5" 0.2 "dvtrp6" 0.0 "dvtrp7" 0.0 "dvtrp8" 0.0 "dvtrp9" 0 "dvtrp10" 0 "dttrp1" 1.0 "dttrp2" 10.0 "dttrp3" 20.0 "dttrp4" "dttrp5" 0.16 "dttrp6" 0.0 "dttrp7" 0.0 "dttrp8" 0.0 "dttrp9" 0 "dttrp10" 0
lhfrt “BUSNAME " "DG" : #9 "fref" "dftrp1" "dftrp2" "dftrp3" 0.5 "dftrp4" 2.0 "dftrp5" "dftrp6" 0.0 "dftrp7" 0.0 "dftrp8" 0.0 "dftrp9" 0.0 "dftrp10" 0.0 "dttrp1" "dttrp2" 300 "dttrp3" 300 "dttrp4" "dttrp5" 0.0 "dttrp6" 0 "dttrp7" 0.0 "dttrp8" 0.0 "dttrp9" 0.0 "dttrp10" 0.0
Residential Dynamic Model
pvd “BUSNAME " "DR" : #9 mva= "pqflag" 1. "xc" 0. "qmx" "qmn" 0.00 "v0" 0.9 "v1" "dqdv" 0.05 "fdbd" "ddn" 0.05 "imax" 1.2 "vt0" 0.00 "vt1" 0.0 "vt2" 2.0 "vt3" 2.0 "vrflag" 1. "ft0" 57.0 "ft1" 57.0 "ft2" "ft3" 63.0 "frflag" 0 "tg" 0.02 "tf" 0.05 "vtmax" 1.2 "lvpnt1" 0.8 "lvpnt0" 0.4 "qmin" -1.3 "accel" 0.7
lhvrt “BUSNAME " "DR" : #9 "vref" 1.00 "dvtrp1" "dvtrp2" -0.3 "dvtrp3" "dvtrp4" 0.1 "dvtrp5" 0.2 "dvtrp6" 0.0 "dvtrp7" 0.0 "dvtrp8" 0.0 "dvtrp9" 0 "dvtrp10" 0 "dttrp1" 1.0 "dttrp2" 10.0 "dttrp3" 20.0 "dttrp4" "dttrp5" 0.16 "dttrp6" 0.0 "dttrp7" 0.0 "dttrp8" 0.0 "dttrp9" 0 "dttrp10" 0
lhfrt “BUSNAME " "DR" : #9 "fref" "dftrp1" "dftrp2" "dftrp3" 0.5 "dftrp4" 2.0 "dftrp5" "dftrp6" 0.0 "dftrp7" 0.0 "dftrp8" 0.0 "dftrp9" 0.0 "dftrp10" 0.0 "dttrp1" "dttrp2" 300 "dttrp3" 300 "dttrp4" "dttrp5" 0.0 "dttrp6" 0 "dttrp7" 0.0 "dttrp8" 0.0 "dttrp9" 0.0 "dttrp10" 0.0
Southern California Edison

9. Study Sensitivities Case Sensitivities DER Model sensitivities
Two load conditions:
Light Load: 15,000 MW
Summer Peak: 24,000 MW
Two DER penetration levels:
50% DER penetration (about 1900 MW)
100% DER penetration (about 3800 MW)
Two separate DER modeling approaches:
100 % Residential (PVD1): Full DER on feeder is modeled as 100% Active Power Control
25% Commercial (REGC_A/REEC_B with Volt-Var Control) vs 75% Residential (PVD1 Active Power Control)
FIDVR and No FIDVR
CMPLDW Sensitivities
Tstall set to 9999 or 0.032
Vstall: set to 0.4 or 0.5
DER Model sensitivities
Residential DER modeled through PVD1 model
Two control modes available and tested Active Power vs. Reactive Power
Active Power control favored with unity power factor as final full simulation
No volt/var or voltage control capability
Commercial REGC_A/REEC_B model
Not accurate representation for aggregate but allows for multiple control strategies to be implemented.
Volt/Var control favored with +/- 0.9 PF for final simulation.
Southern California Edison

10. PV penetration combined
DER penetration:
Max Scenario: MW
Case 1: 100% Residential
3738 MW of DER in Active Power Control (PVD1)
Case 2: 75% Residential vs 25% Utility
MW of DER in Active Power Control
934.5 MW of DER in Volt-Var Control (REGC/REEC_B)
Southern California Edison

11. Main Takeaways LVRT vs HVRT settings
Volt-Var Control vs Active Power Control
Impact on SCE system
Modeling Details (Is PVD1 enough?)
Southern California Edison

12. Scenario A Case: 2021 Topology Load Model DER Model: Contingency:
Load: 14,611 MW
DER: 3,738 MW
ID: 17
Load Model
Tstall: Yes
Vstall: 0.5
DER Model:
Residential (100%):
PVD1
Active Power Control
Commercial (0%): None
Contingency:
Fault: Lugo
Loss of: Lugo – Rancho Vista
Southern California Edison

13. Voltages
Southern California Edison

14. Active Power
Southern California Edison

15. LVRT vs HVRT
No issues observed with LVRT as a result of new CA Rule 21 parameters that expand LVRT to 20 seconds.
Post contingency voltages (after a FIDVR) settle at a very high value (e.g. 1.15, 1.20 p.u.) and may cause tripping of DER due to lack of regulation within the desired time.
Dynamic Voltage Regulation capability will be required for proper renewable integration.
Southern California Edison

16. Volt-Var Control
Southern California Edison

17. Scenario B Case: 2021 Topology Load Model DER Model: Contingency:
Load: 15,000 MW
DER: MW
ID: 23
Load Model
Tstall: Yes
Vstall: 0.5
DER Model:
Residential (75%):
PVD1
Active Power Control
Commercial (25%):
REGC/REEC_B
Volt-Var control
Contingency:
Fault: Lugo
Loss of: Lugo – Rancho Vista
Southern California Edison

18. Active Power Control only
Southern California Edison

19. Volt-Var Control & Active Power Control
Southern California Edison

20. Volt-Var Control vs Active Power Control
APC
VVC + APC
Pinitial
Pfinal
Pdelta
Injection Total
3738
1572
2166
2889
849
60% improvement
APC: Active Power Control
VVC: Volt-Var Control
Southern California Edison

21. Volt-Var Control vs Active Power Control
DERs in the industry are predominantly modeled through PVD1 or CMPLDWG.
PVD1 and CMPLDWG are limited to Active and Reactive Power control and do not control voltage.
Use of the more comprehensive REGC model facilitates modeling this capability.
When modeling VVC, DER aggregate is split into two generators:
One aggregate for the residential portion accounting for 75% of the generation using PVD1 in Active Power Control mode.
One aggregate for the commercial portion accounting for the remaining 25% using REGC_A/REEC_B in Volt-Var Control mode.
Southern California Edison

22. SCE System Impact Sensitivities regarding events including:
FIDVR vs No FIDVR
Fault Type (3ph, DLG, SLG)
CMPLDW sensitivity
Southern California Edison

23. FIDVR
Southern California Edison

24. 3ph Fault at Lugo (tstall = 9999)
Southern California Edison

25. 3ph Fault at Lugo (tstall = 0.032s)
Southern California Edison

26. Fault Type
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27. DLG Fault Voltage Profile (tstall=0.032s)No
Trippings
Southern California Edison

28. SLG Fault Voltage Profile (tstall=0.032s)
Southern California Edison

29. CMPLDW - Vstall
Southern California Edison

30. CMPLDW parameter sensitivity (Vstall)
No DERs tripped for with parameter Vstall of 0.4
485 MW of DERs trip with parameter Vstall of 0.5
Southern California Edison

31. Conclusions
No FIDVR = No Problem: All of the initial results with no FIDVR resulted in a smooth response, with no issues during the transient.
DER models do not aid FIDVR events.
No 3ph fault = Very Local Problem.
Single-line-to-ground faults at Lugo did not cause FIDVR events.
Double-Line-to-Ground at Lugo resulted in some local FIDVR.
3ph fault at Lugo would be a concern if system susceptible to FIDVR, otherwise well behaved.
CA rule 21 addresses LVRT regarding FIDVR but may fall short with HVRT.
If voltages rise over 110%, tripping (cease to operate) will be observed by DERs.
LVRT did not lead to issues while HVRT resulted in multiple trippings.
Voltage control may be needed for successful renewable integration.
Provided that HVRT becomes an issue, certain incentives can be developed (e.g. market) that can enable dynamic regulation throughout the system.
Additional model definitions are required:
DER ride-through requirement based on implementation date.
Model aggregation and control implementation.
Unless SCE experiences a system-wide delayed voltage recovery, in which DERs trip due to lack of voltage regulation (HVRT), system should be capable of handling current forecast of close to 4000 MW of DERs by 2026.
Southern California Edison

32. Raul E. Perez-Guerrero Advanced Technology
Thanks
Raul E. Perez-Guerrero
Advanced Technology