Protection & Control Challenges with Distributed Generation

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1 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Protection & Control Challenges with Distributed Generation Pankaj Sharma, P Eng. Grid Operations Manager Operating Effectiveness Networks Operating Division Hydro One Networks Inc. July 2015

2 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc OBJECTIVES Identify major Protection & Control (P&C) Challenges with Distributed Generation (DG) Connections Discuss Mitigation of P&C Challenges Acknowledge advantages of Transfer-Trip (TT) Application Foster important role of P&C in enabling DG

3 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc AGENDA Background Impacts on P&C assets, Challenges & Solutions Transmission Side Distribution Side Operating issues and mitigations DG Interconnection Protection Challenges Utility Protection Advantages of the Transfer Trip Example of an Islanding event with UFLS operation Summary

4 2015 Hydro One. All rights reserved. BACKGROUND Ontario T & D Operating Effectiveness Hydro One Networks Inc (P&C) Protection & Control Transmission System (Tx) Above 50kV Distribution System (Dx) 50kV & Below 1. Transmission Station (feeders, buses, transformers etc) 2. Transmission lines 1. Distribution Station Fuses, Transformers, Re-closers etc) 2. Distribution lines

(Steam) 226 MW Micro 115 MW (Each project < 10 KW) Wind Solar Bio/CoGen Gas Hydro Other

5 Total DG Connected - mid 2015 Total Distributed Generation connected at Distribution: 2865 MW Bio/CoGen 185 MW Solar 1236 MW Gas 362 MW Hydro 383 MW Wind 473 MW Other (Steam) 226 MW Micro 115 MW (Each project < 10 KW) Wind Solar Bio/CoGen Gas Hydro Other (Steam) Micro 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc

6 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Total DG Connected - mid 2015 Total Distributed Generation connected at Transmission: 3395 MW Wind 3255 MW Solar 140 MW Wind Solar

7 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Transmission & Distribution System Transmission Line 2 Transmission System Transmission Line 1 T1 DESN Transformer Station (TS) T 2 Current Transformer Circuit Breaker Transformer Station (TS) Fence Bus A Bus B Feeder M 1 Feeder M 2 Re-closer Feeder M 3 Feeder M 4 Distribution Station (DS) Fuse T4 F 1 Distribution System F 2 DS Fence DS Transformer F 3

8 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Impacts on P&C assets Transmission Side Impacts on the Transformer Station (TS) Feeder protection Bus protection, Line back-up Transformer protection, Automatic Voltage Reg Ground Potential Rise, Neutralizing Transformer, Neutral Grounding Reactor Existing Special Protection Schemes (Load Rejection and Generation Rejection schemes) Network Management System Under Frequency Load Shedding Impacts on the Transmission Line

9 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Feeder Protection Feeder Protection De-Sensitization - Upgrades Feeder Sympathetic trips - Directioning Out of Phase Re-closing of the Feeder Transfer-Trip (TT), and DG End Open Signal (DGEO) Protection Mis-operation due to DG Transformer Magnetizing Currents - Low Set Blocking Signal Protection coordination with downstream devices Ensure capacity of feeder breaker CT is not exceeded

10 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Bus Protection Low impedance Bus differential protection is not affected but may no longer prove to be secure Bus blocking scheme must be reviewed and may need directioning Bus blocking scheme is not affected by DG for faults occurring on the feeder Bus blocking scheme is affected by DG for faults occurring on the bus

11 Bus Blocking Scheme Feeder Fault 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Transmission System Line 2 Line 1 DESN Transformer Station Fault current flows thru feeder protection and bus protection CTs. 50B-Abus 50B-Bbus T1 T2 Bus A Protection I Abus relay = I T1 + I T2 = I F - 32 ms coordination delay - F1 block signal prevents trip Bus A remains in service. Bus A Bus B Feeder protection operates, sends a bus blocking signal to Bus A. F1-21 F2-21 Bus B Protection I Bbus relay = I T2 + -I T2 = 0 - Bus B also remains in service. F1 CB Feeder 1 opens Feeder 2 Forced Outage Feeder Fault on Feeder F1

12 Bus Blocking Scheme Bus Fault 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Transmission System Line 2 Line 1 DESN Transformer Station 50B-Abus 50B-Bbus T1 T 2 CB s open to trip Bus A Bus A Bus B I Abus relay = IT1 + IT2-32 ms coordination delay CTs add fault current for Bus A; Bus A protection operates F1-21 Blocking signal F2-21 was not sent. I Bbus relay = IT2 + -IT2 = 0 - Bus B remains in service. CTs circulates fault current for Bus B; Bus B remains in service. Feeder #1 Feeder #2 Forced outage Bus Fault with no DG

13 2015 Hydro One. All rights reserved. Bus Blocking Bus Fault Operating Effectiveness Hydro One Networks Inc Transmission System Line 2 Line 1 DESN Transformer Station SOLUTION: Directioning of B bus blocking relays will prevent false operation for faults on A bus. This allows faults to be precisely isolated. T1 Bus A 50B-Abus 50B-Bbus Bus B T2 PROBLEM: With DG present, CT at bus tie measures additional DG fault current which creates an imbalance causing the protection for the healthy Bus B to false operate. Bus forced outage is more widespread than necessary. CTs add fault current for Bus A; Bus A protection operates F1-21 F2-21 Feeder #1 Feeder #2 No fault current at Feeders of bus A thus no operation and blocking signal not sent Feeder 2 protection does not operate because directioned thus blocking signal is not sent Bus Fault with DG on feeder F2 Forced outage

14 Line Protections Transfer Trip 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Line Protections Transfer Trip Line Back-Up Protection Station Supplied by Two Transmission Lines Line 1 Line 2 Forced Outage T1 DESN Transformer Station T2 Bus A Line Back-Up Protection Bus B A fault on one transmission line can be fed by the other transmission line because the transformer station creates a path for electric current between the two lines Line Protections detect the fault and respond by taking the line out of service. M 1 M 2 M 3 M 4 Also, a Transfer Trip Signal is sent to the TS so that the LV CB will open. This cuts off the electrical path between the two lines. In case the Transfer Trip fails however, line back-up protection is required. Line back-up is implemented at the station, and can also signal the LV CB to open during a line fault. All TS s fed by two lines are equipped with Line Back-Up Protection.

15 Line Protections Transfer Trip 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Line Protections Transfer Trip Line Back-Up Protection Station Supplied by One Transmission Line Transmission Line Forced Outage Transformer Station T1 T2 Bus A Line Back-Up Protection Bus B M 1 M 2 Transformer Stations (TS) that are supplied by one line and have no DG s connected downstream, do not require Line Back-Up Protection. This is because there is no current sourcing from within the TS that can feed the fault on the transmission line. The fault is managed by the Line Protections. PROBLEM: Once a DG is connected, the line fault can be fed through the TS by the DG. It is therefore necessary to send a Transfer Trip signal to open the DG CB. However, this station does not have Line Back-Up protections to safeguard against a Transfer Trip failure. If the Transfer Trip had failed, the DG would have fed the fault. SOLUTION: Line Back-Up Protections must be installed at TS if DGs are present. This ensures that line fault will not be fed by DG s if there is a failure on the transfer trip.

16 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Transformer P & C Transformer Differential protection at stations having three winding transformers; needs to be upgraded to provide separate restraint windings Transformer LV breaker re-closing scheme may need changes (sync-check may be needed) Restricted ground fault protection may be required if the NGR impedance is increased

17 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Transformer P & C Overload protections, monitoring of reverse flows, total current harmonics and winding temperatures may also be required ULTC voltage regulation may have to be reviewed/changed for reverse P / forward Q flows Volts/Hertz relay may need to be considered for over-fluxing

18 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc GPR, NT, NGR Increased Ground Fault level increases Ground Potential Rise (GPR) requires Neutralizing Transformer (NT) voltage rating and spare communications ports to be reviewed may be replaced with Optical isolator requires Neutral Grounding Reactor (NGR) size to be reviewed ohms may have to be increased to respect TSC limits (Transmission System Code) Location of communication equipment in relay building may have to be re-assessed

19 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Existing SPS Review existing Special Protection System (SPS) Load Rejection (LR) and Generation Rejection (GR) schemes Modifications may be required New Generation Rejection Schemes may be required

20 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Network Management System (NMS) Upgrades needed to match the changes due to DG HMI display changes are required at NMS and LCC Existing Hub sites capacity issue and new sites Unbundle IED relay failure alarms for selectivity

21 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Network Management System (NMS) Review existing RTU capacities: Protection alarm points Telemetry (Amp / MW) and directioning of quantities Operator control tripping of DG RTU may not be adequate; upgrades, expansion or even replacements may be required Upgrade PCMIS to include DG relay settings (Protection & Control Management Information System)

22 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Under Frequency Load Shedding (UFLS) Review existing UFLS scheme Re-configure feeder selection in UFLS Feeders with DG - to be excluded, or Real time intelligence in selecting feeder under UFLS (dynamic arming), or Extending UFLS to DS and re-closer level

23 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Impacts on Transmission Lines Transmission line protection issues Consideration of: Changes due to on-going protection relay replacement programs and/or Tx connected generations Telecom changes Impacts on re-closing circuit Re-closing schemes & timing Keying of T/T and receiving of DGEO signal

24 Transmission Lines Protection Issues Non-Overlapping Zone 1 Protections Enlarged apparent impedance Current Out feed (Current Reversal) 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc

25 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Non-Overlapping Zone 1 Protections New Generator Terminal Station 1 Zone 1 Zone 1 Terminal Station 2 Existing customers If zone 1 elements are required not to trip fault beyond new tapped generation CB, the instantaneous zone 1 protection will not be overlapping. The gap area between the reaches of two zone 1s must be protected by teleprotection scheme.

26 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Enlarged apparent impedance Terminal Station 1 New Generator I G Z 1 Z 2 Terminal Station 2 I 1 I 2 Z App V 1 I 1 Z I Z I I Z Z I I G 1 L 2

27 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Current Out feed (Current Reversal) New Generator Existing Generator Terminal Station 1 I G_1 I G_2 Z 1 Z 2 I 1 I 2 Z 3 L 1 Terminal Station 2 I 3 When a paralleling path exists, the tapped generation may cause current reversal. The distance element will sense a fault close to the remote station as a backward fault. L 2

28 2015 Hydro One. All rights reserved. P & C Planning, Network Development & Regional Panning Impacts on P&C assets Distribution Side Feeder re-closer controller settings, protection coordination & fuse saving? Need for HV side automatic interrupting device at DS? Incorporate blocking scheme? Un-cleared low level faults between existing HV fuse and station re-closer section? Sympathetic Tripping - false tripping of a healthy feeder on adjacent feeder faults? Need for communications at re-closers?

29 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Operating issues and mitigations ISLANDING Transmission Line 2 Transmission Line 1 DESN T1 Transformer Station (TS) T 2 Planned Outage Current Transformer Circuit Breaker Transformer Station (TS) Fence DG Bus A Bus B Feeder M 1 Feeder M 2 DG Re-closer Feeder M 3 Feeder M 4 Distribution Station (DS) DG DG Fuse T4 F 1 F 2 DG DS Fence DS Transformer F 3

30 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc DG Interconnection Protection Challenges Overcurrent Protection difficult to set at DG locations. Inverters - Maximum current about 1.2 p.u., less if DG running at less than max capacity, so there is not enough difference between load and fault for relay to distinguish using over-current Rely on undervoltage element to trip DG. Does not always work!! Faults far away from PCC not visible to DG.

31 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Challenges What about Distance Protection? Zone 1 = 75-80% of Z1 (Instantaneous fault clearance for overlap zone, and high speed trip for rest). Zone 2 (P) = % of Max Apparent Impedance. (High speed or Fast trip for entire line and backed-up with Time Delay trip, usually 400ms). By setting Zone 2 to 120% of the Max Apparent Impedance for remote 3 phase fault, the relay reach becomes huge. With interface transformer HV winding ungrounded the ground distance protection not applicable

32 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Challenges Inverters limit fault current & maintain constant power factor dynamically. Inverters behaviour during fault is important before determining the suitability of the relaying at the DG. Inverters modeled as a current limiting source

33 2015 Hydro One. All rights reserved. DG Interconnection Protection Typical shortcomings Operating Effectiveness Hydro One Networks Inc DG in-feed to a fault anywhere on the Dx can be virtually identical for inverters. All Dx/Tx faults are in the same direction. Direction cannot be used to avoid tripping for faults on adjacent feeders. Current only, voltage only or distance cannot be used to avoid tripping for faults on adjacent feeders. However, distance offers greater precision compared to overcurrent when reach discrimination is required.

34 2015 Hydro One. All rights reserved. DG Interconnection Protection Typical shortcomings Operating Effectiveness Hydro One Networks Inc DG never is certain of the fault location and whether it needs to trip or ride through. Without TT - DG need to delay tripping (at least 150ms) after the utility trips. Even with the longer delays it is difficult to avoid DG nuisance trips for adjacent feeder permanent faults that are cleared by timed protection elements. Delay may be too long due to declining fault infeeds risk asynchronous reclosing into DG + feeder island.

35 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Utility Protection Utility protection has visibility of entire feeder. Utility feeder protections are capable of selective detection and isolation of all faults on the feeder. With fault location discrimination it is determined whether or not the DG needs to be tripped for a feeder fault condition.

36 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Utility Protection Where current magnitude alone is not sufficient, utility feeder protection use direction to avoid tripping for DG back-feeds to source-side faults (adjacent feeder) Transfer Trip (TT) can extend utility protection to the DG for fast clearing. Sequential delay is unavoidable when DG is not capable of detecting feeder faults & there is no TT

37 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Utility Protection Adaptive Relaying Distribution Generation Control Protection (DGCP) Real Time Automation Controller (RTAC) can provide the mechanism to reconfigure both the sending and receiving protection signals to/from remote field devices and feeder breakers whenever changes occur in the feeder topologies. The Distribution Management System (DMS) sends topology changes to the DGCP and the DGCP automatically re-configures the protection signals based on the new topology. Automatically switching setting groups and summing CTs prior to entering or after exiting back-to-back parallel of feeders.

38 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Utility Protection Adaptive Relaying Blocking the tripping for 44kV reclosers for a loss-of-protection. Ground backup protection at the DS to open the 44kV recloser at the station for a 27.6/13.8/8.2 kv station recloser failure condition. The UFLS infrastructure to allow adaptive relaying by evaluating feeder loading conditions by the DMS and having DMS automatically arm selections in real-time at the TS station, 44kV reclosers and 27.6/13.8/8.2 kv DS station reclosers based on the DG generation and loading to satisfy the target load rejection requirement at the TS. The 27.6/13.8/8.2 kv capacitor banks and voltage regulators can be provided with new controllers and remote control but still switch automatically based on the voltage but with the added remote control switching capability.

39 2015 Hydro One. All rights reserved. Advantages of Transfer Trip Operating Effectiveness Hydro One Networks Inc TIMELESS Deterministic, Most Reliable & Safest NO Non-Detection-Zone Operates for Inadvertent Trips TRANSFER TRIP Facilitates DGEO, LSBS Fault Ride- Through Possible (LVRT, LFRT) Provides Rapid Fault Clearance, Fuse Saving, Power Quality Expedites Restoration Efforts

40 2015 Hydro One. All rights reserved. Example of an Islanding Event Operating Effectiveness Hydro One Networks Inc Sidney TS Configuration P4S (Tx line) L1L4 P3S (Tx line) B1S (Tx line) Q6S (Tx line) L6L4 L6L3 TL3 TL1 T2 T1 T2Q BQ T1B M1 M4 M3 M5 M7 R9S M6 R8S SC1 SC1Q SC2B SC2

41 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Pre-Fault Condition P4S (Tx line) L1L4 P3S (Tx line) B1S (Tx line) Q6S (Tx line) L6L4 L6L3 TL3 TL1 DG: 13MW Total Station Load: 58MW, 30MVAR T2 T2Q 45MW+j9MVar BQ 45.5k V T1 Planned Outage on T1 T1B G/L: A 111A M1 M3 M4 M5 253A 179A SC1 76A 27A SC1Q M7 R9S M6 R8S SC2B 33A 65A SC2 j21mvar

42 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Pre-fault Statuses of Generators on LV feeders Trent Severn TT: Yes 0/5 Sonoco NUG TT: No 6.68/7.2 T2 T2Q BQ T1 T1B M1 M4 M3 M5 Sills Island TT: No 0.65/2.215 Glen Miler TT: Yes 1.6/7.2 Frankford TT: No 0.67/2.4 Sidney GS TT: Yes 0.87/2.8 M7 M6 Hakkesteegt /0.2 Glenburne Farm /0.25 R8S R9S 416 Hwy 33 /0.2 Hagues Reach TT: No 0.3/3.3 SC1 SC1Q SC2B SC2 Meyersburg TT: No 0.84/6 Ranney Falls TT: No 1.43/10.9

43 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Fault Condition P4S L1L4 P3S B1S Q6S L6L4 L6L3 TL3 TL1 T2 T1 T2Q BQ T1B M1 M4 M3 M5 M7 R9S M6 R8S SC1 SC1Q SC2B SC2

44 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc Effect of UFLS on Islanding Event I (R Φ), Feeder M1 Time (ms) 1 0 f U (Hz) (p.u.) P (MW) Events 115kV Line Q6S Fault cleared, Islanding started OPG Generators 81U Pickup 3 I 0 (System, transformers neutral currents) UFLS Stage 1 Pickup V (R W, Φ - Φ), LV Bus UFLS Stage 2 Pickup P, Feeder M Glen Miler DG Tripped (81U setting: 58.4Hz, 0s) Q, Feeder M1 Frequency Feeder M4, M3, M5, M6, M7 tripped due to UFLS All DG tripped except Sills Island Island Collapsed

45 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc SUMMARY and Important Points Identify P&C upgrades at Tx and Dx Detailed P&C assessment should be carried out Adequate feeder characteristics must be provided to customer to determine relay settings at DG end DG inter-tie protection design and relay setting must be reviewed for acceptance Change controls Feeder Model & Configuration, Short circuit levels and DG equipment changes etc.

46 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc SUMMARY and Important Points Challenges in DG protections relay settings Depending upon DG type/locations feeder faults may not be visible to DG protections, issues with O/C & Distance Protection DG protections have inherent disadvantages Difficult trade off between DG protection sensitivity and selective may suffer high number of nuisance trips Utility feeder protections have advantages Sensitive, Selective and Deterministic Advantages of Transfer Trip and Adaptive Relaying to improve DG availability when not required to trip and ensure effective tripping of DGs when required to trip.

48 2015 Hydro One. All rights reserved. Operating Effectiveness Hydro One Networks Inc DISCLAIMER The purpose of this presentation is to provide information about some of the issues that Hydro One Networks Inc. ( Hydro One ) has encountered during the process of connection generation facilities to Hydro One s distribution system. The particular concerns that must be addressed by a generation proponent in respect of the connection of its generation facility to Hydro One s distribution system will be set out in the Connection Impact Assessment that Hydro One performs or has performed, as the case may be, for such proposed connections and this presentation is not intended to amend, modify or replace same. Hydro One will not be liable or be responsible for any consequences of the use or reliance on the information contained in this presentation.

Embedded Generation Connection Application Form

Embedded Generation Connection Application Form This Application Form provides information required for an initial assessment of the Embedded Generation project. All applicable sections must be completed