Hydro One Dg Technical Interconnection Requirements Distribution Interconnections

DISTRIBUTED GENERATION

TECHNICAL INTERCONNECTION

REQUIREMENTS INTERCONNECTIONS AT VOLTAGES 50KV AND

BELOW

Proposal for Stakeholder Consultation

© COPYRIGHT 2009 HYDRO ONE NETWORKS LTD. ALL RIGHTS RESERVED

Rev 0 February 2009

DISTRIBUTED GENERATION TECHNICAL INTERCONNECTION REQUIREMENTS Hydro One Networks Inc. INTERCONNECTIONS AT VOLTAGES 50KV AND BELOW

LIMITATION OF LIABILITY AND DISCLAIMER Hydro One Networks Inc.’s (“Hydro One”) “Distributed Generation Technical Interconnection Requirements: Interconnections at Voltages 50kV and Below” (the “DG Requirements”) identifies minimum requirements for generation projects connecting to Hydro One’s distribution system. Additional requirements may need to be met by the owner of the generation project to ensure that the final connection design meets all local and national standards and codes and is safe for the application intended. The DG Requirements are based on a number of assumptions, only some of which have been identified. Changing system conditions, standards and equipment may make those assumptions invalid. Use of this document and the information it contains is at the user’s sole risk. Hydro One, nor any person employed on its behalf, makes no warranties or representations of any kind with respect to the DG Requirements, including, without limitation, its quality, accuracy, completeness or fitness for any particular purpose, and Hydro One will not be liable for any loss or damage arising from the use of this document, any conclusions a user derives from the information in this document or any reliance by the user on the information it contains. Hydro One reserves the right to amend any of the requirements at any time. Any person wishing to make a decision based on the content of this document should consult with Hydro One prior to making any such decision. STAKEHOLDER CONSULTATION CONTACT

Please forward questions/comments regarding this Document to the following email address:

EMAIL: [email protected] Hydro One has released this document for public stakeholder consultation. The stakeholder consultation process along with an electronic version of this document is available at www.hydroone.com/DG

REVISION HISTORY

DATE VERSION COMMENTS

February 2009 Proposal – Rev 0 New Report

mailto:[email protected]

http://www.hydroone.com/DG

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TABLE OF CONTENTS

TABLE OF CONTENTS ..................................................................................................................................... 1

LIST OF FIGURES ............................................................................................................................................. 5

LIST OF TABLES ............................................................................................................................................... 6

1 INTRODUCTION .................................................................................................................................. 7

1.1 SCOPE ................................................................................................................................................. 8 1.2 DOCUMENT REPRODUCTION .............................................................................................................. 9 1.3 TERMS AND DEFINITIONS ................................................................................................................. 10

2 HYDRO ONE SYSTEM CHARACTERISTICS ................................................................................. 16

2.1 GENERAL CHARACTERISTICS ........................................................................................................... 16 2.2 SYSTEM FREQUENCY ........................................................................................................................ 16 2.3 VOLTAGE ......................................................................................................................................... 16 2.4 VOLTAGE REGULATION ................................................................................................................... 17 2.5 VOLTAGE AND CURRENT UNBALANCE ............................................................................................. 18 2.6 POWER QUALITY .............................................................................................................................. 18 2.7 FAULT LEVELS ................................................................................................................................. 18 2.8 SYSTEM GROUNDING ........................................................................................................................ 19 2.9 HYDRO ONE NETWORKS INC. DISTRIBUTION SYSTEM FEEDER PROTECTION .................................. 19 2.10 AUTOMATIC RECLOSING (FAULT CLEARING) .................................................................................. 20 2.11 PHASING ........................................................................................................................................... 21 2.12 MULTIPLE SOURCE (NETWORKED) SYSTEM ..................................................................................... 21 2.13 FREQUENCY OF INTERRUPTIONS ...................................................................................................... 21 2.14 ABNORMAL CONDITIONS .................................................................................................................. 22

3 DG TECHNICAL INTERCONNECTION REQUIREMENTS .......................................................... 23

3.1 INTERCONNECTION TECHNICAL REQUIREMENTS............................................................................. 24 3.1.1 Safety ......................................................................................................................................... 24 3.1.2 Adverse Effects to HONI Customers ....................................................................................... 24 3.1.3 Point of Common Coupling ...................................................................................................... 24 3.1.4 Point of Disconnection .............................................................................................................. 26 3.1.5 Voltage ....................................................................................................................................... 27 3.1.6 Voltage and Current Unbalance ............................................................................................... 28 3.1.7 Frequency .................................................................................................................................. 29 3.1.8 Power Factor ............................................................................................................................. 29 3.1.9 Capacity Limitations on Generator Interconnections .............................................................. 30

3.1.9.1 Three Phase Generator Interconnections ........................................................................................... 30 3.1.9.2 Single Phase Generator Interconnections .......................................................................................... 30

3.1.10 Phasing Requirements ............................................................................................................. 31 3.1.11 Interconnection Transformer Configuration............................................................................. 31

3.1.11.1 DG Interconnection to 4-Wire Distribution System ........................................................................... 32 3.1.11.2 DG Interconnection to 3-Wire Distribution System ........................................................................... 41

3.1.12 High Voltage Interrupting Device (HVI) ................................................................................... 44 3.1.12.1 Requirement for Interconnection to 4-Wire Distribution System ...................................................... 45 3.1.12.2 Requirement for Interconnection to 3-Wire Distribution System ...................................................... 45 3.1.12.3 Interrupting Time Requirement .......................................................................................................... 45

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3.1.13 Station Service for Critical Loads ............................................................................................. 45 3.1.14 Grounding .................................................................................................................................. 46 3.1.15 Fault Levels ............................................................................................................................... 48 3.1.16 Resonance Analysis ................................................................................................................. 48 3.1.17 Self-Excitation Analysis ............................................................................................................ 49 3.1.18 Islanding..................................................................................................................................... 49 3.1.19 Synchronization ......................................................................................................................... 49 3.1.20 Insulation Coordination ............................................................................................................. 51 3.1.21 Equipment Rating and Requirements ...................................................................................... 51 3.1.22 Operating Requirements .......................................................................................................... 52 3.1.23 Metering ..................................................................................................................................... 53 3.1.24 DG Facility Acceptance ............................................................................................................ 53

3.2 PROTECTION REQUIREMENTS .......................................................................................................... 54 3.2.1 General Requirements .............................................................................................................. 54 3.2.2 Hydro One Networks Inc. Distribution System Feeder Protection......................................... 55 3.2.3 Sensitivity and Coordination ..................................................................................................... 55 3.2.4 Protection Operating Times ...................................................................................................... 55

3.2.4.1 Interrupting Time for Device Disconnecting Generation ..................................................................... 56 3.2.5 Interrupting Device Rating ........................................................................................................ 56 3.2.6 High Voltage Interrupter (HVI) .................................................................................................. 56 3.2.7 Breaker Fail (BF) ....................................................................................................................... 58

3.2.7.1 BF Protection for HVI ............................................................................................................................ 58 3.2.7.2 BF Protection for LVI ............................................................................................................................ 59

3.2.8 Single Phase Generators ......................................................................................................... 59 3.2.9 Three Phase Generators .......................................................................................................... 61

3.2.9.1 Delta:Wye DGIT Connecting to 3-Wire – Preferred ............................................................................ 63 3.2.9.2 Wye-Gnd:Delta DGIT Connecting to 3-Wire - Alternate ..................................................................... 64 3.2.9.3 Wye-Gnd:Delta:Wye-Gnd Connecting to 3-Wire - Alternate .............................................................. 65 3.2.9.4 Wye-Gnd:Delta DGIT Connecting to 4-Wire - Preferred .................................................................... 66 3.2.9.5 Wye-Gnd:Delta:Wye-Gnd Connecting to 4-Wire - Alternate .............................................................. 67 3.2.9.6 Delta:Wye DGIT Connecting to 4-Wire - Alternate ............................................................................. 68

3.2.10 Phase and Ground Fault Protection Requirement .................................................................. 69 3.2.11 Unbalance Protection................................................................................................................ 70 3.2.12 Feeder Relay Directioning ........................................................................................................ 71 3.2.13 Over Frequency/Under Frequency Protection ........................................................................ 71 3.2.14 Overvoltage/Undervoltage Protection ...................................................................................... 73 3.2.15 Anti-Islanding Protection ........................................................................................................... 74 3.2.16 Requirement for Transfer Trip .................................................................................................. 75

3.2.16.1 Possible Exemption for DGs Smaller than 500kW ........................................................................... 76 3.2.17 DGEO (Distributed Generator End Open) ............................................................................... 76 3.2.18 Unintentional Energization........................................................................................................ 76 3.2.19 Connection to Hydro One Network’s System .......................................................................... 77 3.2.20 Disconnection of DG facilities .................................................................................................. 77

3.2.20.1 Disconnecting DG Generation ........................................................................................................... 78 3.2.20.2 Disconnecting DG HV Ground Sources ............................................................................................ 78

3.2.21 Reconnection of DG Facility ..................................................................................................... 78 3.2.21.1 Reconnection of Hydro One Source (for a transient fault) ............................................................... 78 3.2.21.2 DG Facility Reconnection ................................................................................................................... 79 3.2.21.3 Lock-Out of Hydro One Source (For a Permanent Fault) ................................................................ 81 3.2.21.4 Restoration Following a Sustained Outage or Shutdown ................................................................. 82

3.2.22 LSBS (Low Set Block Signal) ................................................................................................... 82 3.2.23 Auto-Resynchronization/Reconnection ................................................................................... 82 3.2.24 Synchronization Protection ....................................................................................................... 83 3.2.25 Telemetry and Targeting .......................................................................................................... 83

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3.2.26 Transformer Protection ............................................................................................................. 84 3.2.27 Protection from Electromagnetic Interference (EMI) .............................................................. 84 3.2.28 Surge Withstand Performance ................................................................................................. 84 3.2.29 Special Interconnection Protection .......................................................................................... 84 3.2.30 Batteries/DC Supply .................................................................................................................. 85 3.2.31 Protection Scheme Failure ....................................................................................................... 86 3.2.32 Teleprotection Scheme Failure ................................................................................................ 86

3.2.32.1 Transfer Trip Channel Failure ............................................................................................................ 86 3.2.32.2 DGEO Channel Failure ...................................................................................................................... 87

3.2.33 Generators Paralleling for 6 Cycles or Less (Closed Transition Switching) ......................... 87 3.2.34 Instrument Transformers for use in Protection Systems ........................................................ 87 3.2.35 Provision for Future Changes .................................................................................................. 87 3.2.36 Interconnection Protection Acceptance ................................................................................... 88 3.2.37 Protection Summary ................................................................................................................. 89

3.3 CONTROL AND TELECOMMUNICATIONS REQUIREMENTS ................................................................. 90 3.3.1 General ...................................................................................................................................... 90 3.3.2 Control Facilities ........................................................................................................................ 91 3.3.3 Telecommunication Facilities ................................................................................................... 91

3.3.3.1 Reliability Requirements ....................................................................................................................... 92 3.3.4 Operating Data, Telemetry and Monitoring ............................................................................. 93

3.3.4.1 Class 1 Generators ............................................................................................................................... 93 3.3.4.2 Class 2 Generators ............................................................................................................................... 93 3.3.4.3 Class 3 Generators ............................................................................................................................... 94 3.3.4.4 Class 4 Generators ............................................................................................................................... 95 3.3.4.5 Telemetry Reporting Rates .................................................................................................................. 95

3.3.5 Monitoring Reporting................................................................................................................. 96 3.4 PERFORMANCE REQUIREMENTS ....................................................................................................... 96

3.4.1 Power Quality ............................................................................................................................ 96 3.4.1.1 Voltage Fluctuations (Flicker) .............................................................................................................. 97 3.4.1.2 Voltage and Current Harmonics........................................................................................................... 97 3.4.1.3 Voltage and Current Unbalance........................................................................................................... 98 3.4.1.4 Limitation of DC Injection ..................................................................................................................... 98

3.4.2 Disturbances .............................................................................................................................. 99 3.4.3 Generator ................................................................................................................................... 99

3.4.3.1 Reactive Power Requirements ............................................................................................................ 99 3.4.3.2 Speed Governors ................................................................................................................................ 100 3.4.3.3 Excitation Equipment .......................................................................................................................... 101

4 METERING REQUIREMENTS ........................................................................................................103

5 CONNECTION PROCESS REQUIREMENTS .................................................................................103

5.1 IMPLEMENTATION ...........................................................................................................................103 5.2 CONNECTION AGREEMENT ..............................................................................................................104

6 COMMISSIONING AND VERIFICATION REQUIREMENTS ......................................................105

6.1 HYDRO ONE NETWORKS INC. COVER PROCESS ...........................................................................105 6.2 HYDRO ONE REQUIREMENTS FOR COMMISSIONING AND VERIFICATION ........................................105

7 MAINTENANCE REQUIREMENTS ................................................................................................107

7.1 PROTECTION AND CONTROL SYSTEMS EQUIPMENTS ......................................................................107

8 REPORTING REQUIREMENTS FOR DGS .....................................................................................108

9 REFERENCES ....................................................................................................................................110

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A APPENDIX A - DEVICE NUMBER DESCRIPTION .......................................................................113

B APPENDIX B – NEUTRAL REACTOR AND GROUNDING TRANSFORMER IMPEDANCE

CALCULATIONS FOR INVERTER BASED DG FACILITIES ......................................................114

C APPENDIX C – TIMING DIAGRAMS ..............................................................................................115

D APPENDIX D – ANTI-ISLANDING PROTECTION ........................................................................119

E APPENDIX E – DGEO & LSBS DESIGN CONSIDERATIONS ......................................................134

F APPENDIX F – EXAMPLE OF A SEQUENCE OF EVENTS DURING FAULT CONDITIONS...135

G APPENDIX G – CONFIRMATION OF VERIFICATION EVIDENCE REPORT ..........................137

H APPENDIX H – DISTRIBUTION POLICY – METERING FOR DG - NOP 041 ...........................145

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List of Figures

FIGURE 1: SIMPLIFIED SLD – SHOWS CLEARLY IDENTIFIED PCC .......................................................................... 25

FIGURE 2: PREFERRED DGIT CONFIGURATION FOR 4-WIRE DISTRIBUTION SYSTEMS ............................................. 34

FIGURE 3: ALTERNATE DGIT CONFIGURATION FOR 4-WIRE DISTRIBUTION SYSTEMS ............................................ 36

FIGURE 4: ALTERNATE #2 DGIT CONFIGURATION................................................................................................. 39

FIGURE 5: ALTERNATE DGIT CONFIGURATION FOR FACILITIES < 1 MVA .............................................................. 40

FIGURE 6: PREFERRED DGIT CONFIGURATION FOR 3-WIRE DISTRIBUTION SYSTEM ............................................... 42

FIGURE 7: ALTERNATE DGIT CONFIGURATION FOR 3-WIRE DISTRIBUTION SYSTEM .............................................. 43

FIGURE 8: ALTERNATE DGIT CONFIGURATION FOR 3-WIRE DISTRIBUTION SYSTEM .............................................. 44

FIGURE 9: EXAMPLE PROTECTION FOR A SINGLE PHASE GENERATOR ................................................................... 60

FIGURE 10: PREFERRED CONNECTION FOR 3-WIRE DISTRIBUTION SYSTEM ............................................................ 63

FIGURE 11: ALTERNATE CONNECTION FOR 3-WIRE DISTRIBUTION SYSTEM ........................................................... 64


FIGURE 13: PREFERRED CONNECTION FOR 4-WIRE DISTRIBUTION SYSTEM ............................................................ 66



FIGURE 16: NPCC DIRECTORY D2 REQUIREMENT ............................................................................................... 72

FIGURE 17: NO TRANSFER TRIP WITH 500MS RECLOSURE UPSTREAM ..................................................................115

FIGURE 18: NO TRANSFER TRIP WITH 1S RECLOSURE UPSTREAM ........................................................................116

FIGURE 19: TRANSFER TRIP WITH 500MS RECLOSURE UPSTREAM ........................................................................117

FIGURE 20: TRANSFER TRIP WITH 1S RECLOSURE UPSTREAM ..............................................................................118

FIGURE 21: TYPICAL DISTRIBUTION SYSTEM WITH DG INTERCONNECTIONS .........................................................129

FIGURE 22: DGEO & LSBS DESIGN CONSIDERATION .........................................................................................134

FIGURE 23: SEQUENCE AND TIMING DIAGRAM FOR TRANSIENT FAULTS ..............................................................135

FIGURE 24: SEQUENCE AND TIMING DIAGRAM FOR PERMANENT FAULT ...............................................................136

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List of Tables

TABLE 1: VOLTAGE LIMITS 0 TO 50,000V ON DISTRIBUTION SYSTEM ................................................................... 17

TABLE 2: OPERATING FREQUENCY RANGE ........................................................................................................... 29

TABLE 3: RESYNCHRONIZATION REQUIREMENTS .................................................................................................. 50

TABLE 4: ARRESTER RATINGS .............................................................................................................................. 51

TABLE 5: TYPICAL PROTECTIONS REQUIRED FOR SINGLE PHASE DG FACILITIES ................................................... 60

TABLE 6: TYPICAL PROTECTIONS FOR THREE PHASE DGS ..................................................................................... 62

TABLE 7: OVER/UNDER FREQUENCY PROTECTION SET POINTS AND CLEARING TIMES ........................................... 72

TABLE 8: OVER/UNDER VOLTAGE PROTECTION SETTING AND CLEARING TIME ..................................................... 73

TABLE 9: DG CLASSIFICATION ............................................................................................................................. 90

TABLE 10: UNPLANNED TELECOMMUNICATION FAILURE RATES AND REPAIR TIMES.............................................. 92

TABLE 11: TELEMETRY REPORTING RATES........................................................................................................... 95

TABLE 12: PST AND PLT FLICKER LIMITS ............................................................................................................. 97

TABLE 13: CURRENT HARMONIC LIMITS .............................................................................................................. 98

TABLE 14: INCIDENT LOGGING ...........................................................................................................................109

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1 Introduction

This ―Distributed Generation Technical Interconnection Requirements – Interconnections at

Voltages 50kV and Below‖ outlines the technical requirements to install or modify

Distributed Generation (DG) projects connected to HONI‘s sub-transmission and

distribution (systems at ≤ 50kV) feeders. Technical requirements are defined accordingly to

the size and type of generation. This document is designed to provide an expeditious

interconnection to Hydro One Networks Inc. sub-transmission and distribution system that

is both safe and reliable.

This document, ―Hydro One Networks Inc. Distributed Generation Technical Interconnection

Requirements – Interconnections at Voltages 50kV and Below‖ was prepared by Hydro One

Networks Inc. (henceforth referred to as HONI) to guide generator owners and proponents

in connecting distributed generators (DGs) to HONI‘s distribution and sub-transmission

system. It applies to all interconnecting generators.

The additions of DGs to HONI‘s system introduces changes to the sub-transmission and

distribution system and its response. It is imperative that a technically sound, reliable and

safe interconnection between the DGs and HONI is achieved and this requires diligence

from all parties involved. The requirements in this guideline need to be understood by

designers, consultants, equipment vendors, manufacturers, DG owners, and operators of

the DG‘s and HONI‘s system. These requirements will ensure that the interconnection of

the DG to HONI‘s system will:

protect the integrity of HONI system and guarantee reliable and quality service to

HONI‘s customers,

ensure that the interconnection is safe at all times for HONI‘s employees, HONI‘s

customers, DG owners and operators, and for the general public.

be consistent with the requirements of the OEB and all applicable standards

meet all of HONI‘s protection, operating and metering requirements.

This interconnection standard has been developed with reference to the Canadian

Standards Association such as C22.3 No. 9-08 – Interconnection of Distributed Resources

and Electricity Supply Systems and international standards such as the Institute of

Electrical and Electronics Engineers (IEEE) Standard 1547 – Draft Application Guide for

IEEE Standard 1547, Interconnecting Distributed Resources with Electric Power Systems.

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This document does not constitute a design handbook. DG owners who are considering

the development of a generation facility intended for connection to HONI‘s system1 should

engage the services of a professional engineer and/or a registered consulting firm qualified

to provide design and consulting services for electrical interconnection facilities in the

Province of Ontario.

1.1 Scope

This document establishes criteria and requirements for the interconnection of DGs to

the distribution and sub-transmission system. It has been tailored specifically to define

the requirements for connecting DGs to HONI‘s distribution and sub-transmission

system with an operating voltage of 50,000 volts (50kV) or lower. It applies to all

induction generators, synchronous generators and inverter-based generators (solar

photovoltaic, fuel cell, induction generator with a static power converter or permanent

magnet generator with a static power converter). This document contains information

pertaining to HONI‘s system and identifies potential issues, such as protection, safety,

coordination, reliability and operation which shall be considered at different stages of the

project.

Chapter 2, ―Hydro One System Characteristics‖ provides operating characteristics of

HONI‘s sub-transmission and distribution system. It has been included in this document

to ensure that DG owner is aware of HONI‘s sub-transmission and distribution system

behaviour. Chapter 2 contains no requirements for the interconnection of DGs and has

been provided for informational purposes only.

The following sections of this document constitute the requirements that the DG owner

must comply with in order to connect to HONI‘s systems:

Chapter 3 - DG Technical Interconnection Requirements

Chapter 4 - Metering Requirements

Chapter 5 - Connection Process Requirements

Chapter 6 - Commissioning and Verification Requirements

Chapter 7 - Maintenance Requirements

Chapter 8 - Reporting Requirements for DGs

1 This document also applies to DGs connecting to Hybrid Feeders (feeders owned partially by HONI)

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Certain requirements have a separate ―Design Considerations‖ heading which is clearly

defined. This information has been provided for informational purposes to aid in the

design of the DG facility in certain cases and does not represent a requirement. HONI

does not take any responsibility for this information and the engineering consultant

designing the DG facility can decide whether to take the information into consideration

when designing the project.

It is the DG owner‘s responsibility to ensure that all requirements are met. These

requirements have been developed to ensure that HONI‘s sub-transmission and

distribution system is protected from the DG facility. Additional requirements may be

necessary to address unique situations and the DG owner shall be advised of any such

requirements at the appropriate stage.

Certain requirements of this document state that a deviation from the preferred option

(alternative) is available or that certain requirements may be not apply for certain

installations. Any exemptions require written approval from HONI.

This document does not identify any generator protections and the DG Owner shall

ensure that adequate generator protections are installed that will protect the generator

from any situation, including problems originating from HONI‘s sub-transmission and

distribution system.

1.2 Document Reproduction

This document may be reproduced or copied in whole or in part provided that credit is

given to Hydro One Networks Inc. and is not sold for profit.

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1.3 Terms and Definitions

The Term Is defined as…

ANSI American National Standards Institute

Anti-Islanding Protection system aimed at detecting islanded conditions (see island) and tripping the DG facility from the distribution system if an island forms

AVR Automatic Voltage Regulator

BF Breaker Fail

Breaker Fault Interrupting Device – may be a breaker, circuit switcher, HVI, LVI

CCRA Connection Cost Recovery Agreement

CEA The Canadian Electricity Association

CIA Connection Impact Assessment

Class 1 DG DG aggregate capacity at PCC < 250kW

Class 2 DG 250kW ≤ DG aggregate capacity at PCC < 1500kW

Class 3 DG 1.5MW ≤ DG aggregate capacity at PCC < 10MW

Class 4 DG DG aggregate capacity at PCC > 10MW

Clearing Time See Trip Time

CO

Central Office – A local telephone company office that provides a central point for the termination of telecommunication lines and trunks. And where they can be interconnected.

CSA The Canadian Standards Association

DESN Dual Element Spot Network – Type of TS

Distributed Generation (DG)

Unregulated power generators connected to a distribution system through a Point of Common Coupling

Distributed Generator (DG)

See Distributed Generation

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Distributor The electric utility owning or operating the distribution lines

Distribution System

Any power line facilities under the operating authority of the Wires owner (HONI or LDC). Distribution power line facilities usually operate below voltages of 27.6kV nominal, line to line

DG See Distributed Generation *Formerly referred to as EG – Embedded Generator

DGEO

Distributed Generator End Open – A Signal used to confirm the status of the generator breaker – used to prevent out-of-phase reclosing onto the generator *Formerly referred to as EGEO – Embedded Generator End Open

DGIT See DG Interconnection Transformer

DG Facility All equipment including generators, interface transformer, protections, and line on DG side of the PCC

DG Interconnection Transformer

The transformer used to step up the voltage from the DG to distribution levels

DG Owner The entity which owns or leases the DG facility

DS Electrical station that is used to step down a sub-transmission voltage to a distribution voltage for distribution to the end use customer

DSC Distribution System Code

EMI Electromagnetic Interference

ESA Electrical Safety Authority

F Class Feeder Distribution feeder emanating from a HONI DS or HVDS

Feeder a single 1 phase or 3 phase line emanating from a substation to supply load

Ferroresonance

Phenomenon caused by the interaction of system capacitance and nonlinear inductance of a transformer, usually resulting in very high transient or sustained overvoltage

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GPR

Ground Potential Rise – IEEE defines this as the voltage that a station grounding grid may attain relative to a distant grounding point assumed to be at the potential of remote earth

Harmonics Sinusoidal voltages and currents at frequencies that are integral multiples of the fundamental power frequency

High Voltage In this document, high voltage refers to HONI system voltage – can be referred to as medium voltage

HONI Hydro One Networks Inc.

HVDS

High Voltage Distribution Station – Distribution station connected directly to HONI transmission system (115kV system). Stepping down transmission voltage to distribution voltage for distribution to the end use customer

HVI High Voltage Interrupter – any breaker/fault clearing device that is on the HONI side of the DGIT – voltage rating is usually at medium voltage distribution level

Hybrid Feeders Feeders owned partly by HONI and partly by other entities (e.g. HONI owns the first 50% of the feeder, and an LDC own the rest of the feeder).

IEEE The Institute of Electrical and Electronics Engineers

IED Intelligent Electronic Device

IESO Independent Electricity System Operator

Interconnection facility

Physical connection of DG to HONI's distribution system which allows parallel operation to occur

Interconnection Point

See PCC

Island An operating condition where a DG(s) is (are) supplying load(s) that are not paralleled and synchronized with the main electric utility (electrically separated)

LDC Local Distribution Company. An entity that owns a distribution system for the delivery of energy to consumers from the IESO-controlled grid

Load The amount of power supplied or required at a specific location

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Load Factor Ratio of average load during a designated period to the peak (maximum) load in the same period

Load Flow Study Steady state computer simulation study of voltages and currents in the distribution system

LSBS

Low Set Block Signal – signal sent over same channel as DGEO which blocks the Low Set Instantaneous Protections at HONI‘s stations to prevent inadvertent trips due to transformer inrush during energization.

LVI Low Voltage Interrupter

Medium Voltage See High Voltage

M Class Feeder Distribution feeder emanating from a HONI TS – usually ≥ 24.9kV

NDZ Non Detection Zone – range where passive anti-islanding protection may not operate within required time due to the small mismatch between generation and load

NPCC NorthEast Power Coordinating Council

OEB Ontario Energy Board

OESC Ontario Electrical Safety Code

OGCC Ontario Grid Control Centre

Parallel Operation The state and operation where the DG Facility is connected to the Sub-transmission or Distribution System and supplying loads along with the electric grid.

PCC Point of Common Coupling

Point of Connection The point where an interconnection system is electrically connected to the DG facility. Can be the same as PCC. Refer to Figure 1 for details.

Pst A measure of short-term perception of flicker obtained for a ten minute interval

PSS Power System Stabilizer

Plt A measure of long-term perception of flicker obtained for a two-hour period

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Protection Scheme Protection functions, including associated sensors, relays, CTs, PTs, power supplies, intended to protect a distribution system or interconnected facility

SLD Single Line Diagram

Resonance A tendency of a system to oscillate at maximum amplitude at certain frequencies, usually resulting in very high voltages and currents

RLSS Rotational Load Shedding Schedules

Stabilized Distribution System returning to normal (frequency and voltage) after a disturbance for a period of 5 minutes or as determined by the Wires Owner

Sub-transmission 27.6kV or 44kV HONI distribution lines

Synchronized See Parallel Operation

Telemeter Transfer of metering data using communication systems

THD

Total Harmonic Distortion – a measurement of the harmonic distortion present. It is defined as a ratio of the sum of the powers of all harmonic components to the power of the fundamental frequency

TOV Temporary Overvoltage – oscillatory power frequency overvoltages of relatively long duration – from a few cycles to hours.

Transmission System

Any power line facilities under the operating authority of the Wires Owner usually operating at higher then 50kV voltages, line to line

Transfer Trip A signal sent over communication channels from upstream devices commanding the DG to disconnect from HONI's distribution system

Trip Time The time between the start of the abnormal condition to the time where the system disconnects and ceases to energize the distribution system

TS Electrical station that is used to step down transmission voltage to a sub-transmission voltage for distribution to the end use customer and DS stations

TT See Transfer Trip

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Type Test Test performed on a sample of a particular model/device to verify its operation and design

Wires Owner Utility which owns and/or operates the distribution system

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2 Hydro One System Characteristics

This section describes the characteristics of Hydro One Networks Inc. Distribution System

and identifies aspects that must be taken into consideration when designing a generation

facility that will be interconnected with HONI‘s distribution system. The DG owner must be

able to operate within the ranges specified in this section. In this document, HONI‘s

distribution system may refer to either three phase systems or single phase systems

operating at voltages of 50kV and below – includes systems falling under the definition of

distribution and sub-transmission system. This section contains no requirements for the

interconnection of DGs and has been provided for informational purposes only.

2.1 General Characteristics Most distribution circuits (feeders) in HONI‘s distribution system are supplied radially

from a single substation (point of supply). In some areas, some feeders may have

alternate points of supply, but will be operated with more than one source of supply only

momentarily during switching operations. HONI‘s distribution feeders operate at the

following voltages (phase-phase/phase-neutral): 44kV (3-Wire), 27.6/16kV, 25/14,4kV,

13.8/8kV, 12.48/7.2kV, 8.32/4.8kV, 4.16/2.4kV.

2.2 System Frequency The nominal frequency of HONI‘s system is 60Hz. During normal operation (steady

state), the frequency may deviate from 59.3Hz to 60.5Hz, or as supplied by the

transmission system. Under contingencies the frequency deviations may be larger.

2.3 Voltage The CSA Standard CAN3-C235-83 ―Preferred Voltage Levels for AC Systems, 0 to

50,000V Electric Power Transmission and Distribution‖ provides general guidance for

the steady state service voltage levels on the distribution system. Customers supplied

by the distribution feeder must have adequate voltage levels as per this standard, with

and without distributed generation supplying power for minimum and maximum loading

conditions. The operating voltages found on the distribution feeder vary depending on

load variation, generation variation and contingency situations. Hydro One Networks

standard for voltages on HONI‘s distribution system at the point of delivery during

normal operation is typically in the range of +/- 6% of nominal voltage. The CSA voltage

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standard (summarized below in Table 1) and the voltage levels at the PCC specified in

the CIA report to the DG Owner should be followed by the DG owner.

These values may be exceeded under abnormal conditions. Voltage transients and

swells can occur on the distribution system at any time due to lightning strikes, single

phase to ground faults, and switching, among others. The interconnected DG must be

able to operate within the extreme voltage level variations shown in this document and

must ensure that the insulation levels and protective equipment in their facility can

withstand abnormal voltages on the distribution system.

Table 1: Voltage Limits 0 to 50,000V on Distribution System

Low Limit (% of nominal) Nominal Voltage (%) High Limit (% of nominal)

94 100 106

2.4 Voltage Regulation HONI utilizes voltage regulating devices throughout the distribution system to maintain

an adequate voltage profile along the feeders and ensure that customers receive

voltages in the range specified in CSA CAN3-235-83. These regulating devices include

line voltage regulators, regulating stations and transformer under-load tap changers at

the Transformer Station (TS) or Distribution Station (DS). HONI operates all voltage

regulating devices on its distribution system to 125V ±1.5V on a 120V base.

The distribution system was designed to correctly operate for unidirectional power flow

(from the substation to the customer). Voltage regulating devices were designed to

correctly operate under these conditions, however, with the addition of DGs into the

system, the power flow can be reversed when the DG is supplying power which may

inhibit the voltage regulators to properly regulate the voltage on the feeder. Due to this,

wherever there is a possibility of reverse power flow, regulating devices (line voltage

regulators, regulating stations and transformer under-load tap changers at the

Transformer Station (TS) or Distribution Station (DS)) on HONI‘s distribution system

shall be changed to suitable devices that allow bi-directional flow.

Steady-state voltage variations at the point of common coupling (PCC) and throughout

the distribution system are limited to +/- 6% of the nominal voltage.

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2.5 Voltage and Current Unbalance Voltage unbalance due to unbalanced loading and single phase voltage regulation is

typical and inevitable and may reach 2% voltage and 10-20% of total feeder load current

unbalance along certain sections of the feeder, including at the PCC. The DG facility

must not further deteriorate existing unbalanced conditions. In some areas of HONI‘s

distribution system these unbalances may be higher and the DG owner shall contact

HONI to obtain site-specific data. During abnormal conditions such as faults and single

pole reclosing, the unbalance may be very high (current unbalance may be significantly

higher than 20%).

As per NEMA MG 1-1998, the formula for voltage unbalance is:

𝑉𝑜𝑙𝑡𝑎𝑔𝑒 𝑈𝑛𝑏𝑎𝑙𝑎𝑛𝑐𝑒 % =100 ×(𝑚𝑎𝑥𝑖𝑚𝑢𝑚 𝑣𝑜𝑙𝑡𝑎𝑔𝑒 𝑑𝑒𝑣𝑖𝑎𝑡𝑖𝑜𝑛 𝑓𝑟𝑜𝑚 𝑎𝑣𝑒𝑟𝑎𝑔𝑒 𝑣𝑜𝑙𝑡𝑎𝑔𝑒 )

(𝑎𝑣𝑒𝑟𝑎𝑔𝑒 𝑣𝑜𝑙𝑡𝑎𝑔𝑒 )

2.6 Power Quality In HONI‘s distribution system, all interconnected equipment must comply with HONI‘s

standards for power quality. IEEE Std. 519, IEEE Recommended Practices and

Requirements for Harmonic Control in Electric Power Systems, has been accepted by

industry to provide guidance for appropriate performance and power quality limits such

as voltage flicker and harmonic contribution limits. This standard states that the

recommended practice for utilities is to limit individual frequency voltage harmonics to

3% of the fundamental frequency and the total voltage harmonic distortion (THD) to 5%

on the utility side of the PCC. These limits presented in this standard should be used as

a design criterion when designing the DG facilities as worst case scenario under normal

operation conditions.

2.7 Fault Levels Fault levels on HONI‘s distribution system vary greatly throughout the system. Factors,

such as location, generation pattern, and contingencies all contribute to varying fault

levels. These fault levels may also change with time as the system expands and new

generation comes online. The DG proponents will receive fault levels for the

distributions system as well as system impedances for a site that is considered from

Hydro One Networks. Maximum allowable fault levels will be provided as well.

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The DG interconnection facilities shall be designed with the fault levels, and maximum

allowable fault levels considered. The X/R ratios must be evaluated for the equipment

selected and the DG facilities shall not increase the fault levels beyond the distribution

system design levels for maximum faults. If the levels increase beyond the existing

design limits, changes to the distribution system equipment will be required.

2.8 System Grounding HONI‘s distribution facilities are typically operated as uni-grounded (for 3 phase – 3 wire

systems) or multi-grounded (for 3 phase – 4 wire systems). The transformer neutral at

the substation is either solidly grounded (without any impedance) or effectively grounded

through a low impedance at the station (through a neutral reactor, resistor or grounding

transformers) to limit the fault levels on ground faults.

Distribution facility and DG facility grounding shall conform to the Ontario Electric Safety

Code (OESC) and Section 10 of the Canadian Electrical Code.

2.9 Hydro One Networks Inc. Distribution System Feeder Protection

HONI will provide to the DG Owner, upon request, all applicable information about

HONI‘s distribution system protection scheme on the feeder interconnecting with the DG

facility. The general feeder protection scheme utilized on HONI‘s distribution system

where DGs are interconnecting is described below for M Class feeders emanating from

TSs. The feeder protections can be divided into three states:

High Set Instantaneous – Instantaneous protection for close-in feeder faults.

Usually set to the first tap on the feeder. Traditionally employed High Set 50A/50NA

elements. Current HONI standard for feeders with DGs interconnected is to use the

Zone 1 distance (21 – Phase & Ground) element to set the High Set Instantaneous

protection.

Low Set Instantaneous – Instantaneous protection for faults on the entire length of

the feeder. Used primarily as a fuse saving scheme to clear transient faults before

fuse elements start melting. Traditionally utilized using Low Set 50B/50NB

elements. Current HONI standard for feeders with DGs interconnected is to use the

Zone 2 distance (21 – Phase & Ground) element to set the Low Set Instantaneous

protection.

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Timed – Directionally supervised 51/51N overcurrent elements load/fault

discrimination are used for timed protection of HONI‘s distribution feeders. They are

set to detect and clear faults in their required zone. All timed overcurrent elements

on the distribution system are coordinated with each other to ensure that a minimum

number of customers are affected in the case of permanent faults. For the timed

overcurrent elements to function properly, all DG sources (both positive sequence

and zero sequence sources) need to be removed from the distribution system –

refer to the requirements in Section 3.1.12 – High Voltage Interrupting Device.

F Class feeders, radiating from DSs, have varying levels of sophistication in their

protection schemes. The protections scheme on F Class feeders may need to be

upgraded to accommodate DGs.

2.10 Automatic Reclosing (Fault Clearing) HONI‘s sub-transmission and distribution system, utilizes automatic reclosing to quickly

clear non permanent faults on the sub-transmission and distribution system, thus,

quickly restoring supply. Generally feeder circuit breakers at Transmission Stations use

single-shot reclosing and reclosers at Distribution Stations and other locations along the

distribution feeder may use single-shot or multi-shot automatic reclosing. Reclosers

may trip a single phase, when single phase loads are connected to the feeder, or all

three phases. If, after the preset number of reclose attempts, the fault persists, the

recloser will lockout and stay open (single phase or three phases will be tripped). The

reclose ―dead time‖ (time that the distribution line is de-energized between reclose

attempts) varies depending on location and type of recloser and can be obtained from

HONI along with all other relevant protection data.

The DG facilities shall be designed with auto-reclosing considered. The generator

protections need to coordinate with the reclosing times of HONI‘s interrupting devices to

ensure that HONI‘s distribution system will not attempt to reclose when the DG is still

connected, risking an out-of-phase reclosing (refer to Section 3 for requirements). If

single phase tripping is employed on HONI‘s distribution system, the DG shall be

designed to protect itself from the unbalance that results. The DG may reconnect to the

system after HONI‘s system voltage and frequency return to nominal and after the

requirements of Section 3.2.19 and Section 3.2.21 of this document are met.

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2.11 Phasing Conductor phasing may not be standardized and as such, the phase sequence and the

direction of rotation shall be coordinated between the DG proponent and HONI.

2.12 Multiple Source (Networked) System In some areas of HONI‘s distribution, there may be instances where portions of a

distribution feeder are supplied from two different sources (such as during switching

events). The added complexity in these instances shall be considered when designing

the DG facilities and every precaution shall be taken to ensure that out-of-phase

reclosing does not occur whenever interconnecting to a networked system or a system

capable of source transferring.

The DG facility is required to be removed from service if the source (normal feed) has

changed from the one studied in the CIA and remain disconnected until normal supply

has been restored.

If this requirement changes and multiple sources (alternate feeder) configurations

become available for DGs, this document will be updated to reflect any policy changes.

The DG Owner will be required to have additional protections to alternative feeder

supplies at that time if they wish to have the capability of connecting to alternate

sources.

2.13 Frequency of Interruptions HONI‘s distribution feeders are mainly unshielded overhead lines spanning vast

distances. They are equipped with insulation levels adequate to withstand expected

voltages. Lighting strikes directly to HONI‘s distribution line result in flashovers of the

insulators on the feeder and result in protection systems tripping the distribution line.

The faults may be temporary in which case a successful reclose will occur (most faults

on overhead distribution lines are temporary in nature), or they may be permanent and

trip the line until repair crews are dispatched and repair the feeder.

Due to the vast distances of the lines and the possibility of frequent momentary trips, the

DG proponent should consider a design that will be suitable for these conditions (such

as auto-restart).

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2.14 Abnormal Conditions The DG Owner shall consider all possible disturbances which occur on HONI‘s

distribution system while designing their protection system to ensure that HONI‘s

customers and the DG facility are protected. These disturbances can include, but are

not limited to the following:

Faults on the system

Frequency excursions

Partial or complete loss of load

Transient overvoltages – caused by lightning strikes or switching operations

Temporary overvoltages

Single phasing of the three phase system – caused by HONI‘s protection

equipment, switching or broken conductors

Ferroresonance, overvoltages due to resonance conditions

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3 DG Technical Interconnection Requirements

This ―DG Technical Interconnection Requirements‖ section defines and describes the

technical requirements for the distribution system, and the generation facility (generators

and interconnection equipment as described in the Distribution System Code) for DG

interconnection. The first part, Section 3.1, defines the interconnection technical

requirements, the second part, Section 3.2, defines the protection requirements, the third

part, Section 3.3, defines the control, telecommunications, and monitoring requirements for

interconnected DGs and the fourth part, Section 3.4 defines the performance requirements

such as power quality and reactive power requirements. These requirements need to be

followed in order to connect to HONI‘s sub-transmission, distribution system and hybrid

feeders. In this document, HONI‘s distribution system may refer to either three phase

systems or single phase systems operating at voltages of 50kV and below – includes

systems falling under the definition of distribution and sub-transmission system. They

encourage safe operation and minimize the impact that the DG facility has on HONI‘s

distribution system and in turn to HONI‘s customers. Certain requirements in Section 3 of

this document state that a deviation from the preferred option (alternative) is available or

that certain requirements may be not apply for certain installations. Any exemptions require

written approval from HONI.

Certain requirements have a separate ―Design Considerations‖ heading which is clearly

defined. This information has been provided for informational purposes to aid in the design

of the DG facility in certain cases and does not represent a requirement. HONI does not

take any responsibility for this information and the engineering consultant designing the DG

facility can decide whether to take the information into consideration when designing the

project.

Beyond the requirements presented here in this document, the DG facility must meet all

applicable national, provincial, local and other HONI safety and construction codes. This

guide is intended to provide protection to HONI‘s distribution system and does not cover

protection of the DG facilities. It is the responsibility of the DG Owner to protect its facilities

in a manner that will ensure that events such as outages, short circuits, unbalances,

excessive zero sequence currents and negative sequence voltage, and other disturbances

do not cause damage to the DG facility.

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3.1 Interconnection Technical Requirements

3.1.1 Safety

The DG interconnection shall not create a safety hazard to HONI‘s personnel,

customers, general public and personnel working in the DG facility. Safety is of

primary concern and should be the main consideration when designing the facility.

The primary concern of this document is to provide interconnection specifications

to ensure that safety will be maintained. All equipment shall be approved by the

appropriate authorities (e.g. CSA). The DG facility must have ESA approval prior

to a Distribution Connection Agreement with HONI. The DG facilities must be

maintained throughout the life of the assets to ensure that the DG facility is

operating as designed.

3.1.2 Adverse Effects to HONI Customers

The interconnection of the DG facilities must not materially compromise the

reliability or restrict the operation of HONI‘s distribution system.

The interconnection must not degrade power quality below acceptable levels and if

it is found that it significantly deteriorates the performance of the distribution

system, it shall be disconnected from the distribution system until appropriate

measures are taken to mitigate these negative impacts.

3.1.3 Point of Common Coupling

The Point of Common Coupling (PCC) is the location where Hydro One Networks

distribution facilities (wires) are connected to the DG Facilities or DG proponent‘s

wires and where the transfer of electric power between the DG and HONI takes

place. The PCC must be identified on the single line diagram (SLD), as shown

below in Figure 1.

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Figure 1: Simplified SLD – Shows Clearly Identified PCC

The DG owner is responsible for the design, construction, maintenance and

operation of the facilities and equipment on the DG side of the PCC (all equipment

on the DG side of the PCC shall be approved in accordance with Section 2-004 of

the Ontario Electrical Safety Code) while HONI will coordinate the design,

construction, maintenance and operation of the facilities on HONI‘s side of the

PCC. HONI will carry out the engineering, design and construction required for

additional changes to HONI‘s system in order to facilitate the DG interconnection.

The DG owner may be responsible for the cost of such changes.

In certain instances, either HONI or the DG owner may require that their

equipment be located on the other side of the PCC. If this is the case, the DG

owner must provide the necessary space for HONI to install such equipment and

HONI is to approve this site. A 120V AC power service is to be available.

When specifications and parameters (such as voltage, frequency, and power

quality) are mentioned throughout this document, they must be met at the PCC

unless otherwise stated throughout the document.

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3.1.4 Point of Disconnection

To ensure a means of electrically isolating the DG facility from HONI‘s distribution

system, a means of isolation must be provided (Load Break Switch) and must be in

compliance with the OESC. To conform with recognized standards (this complies

with OESC Rule 84-026, IEEE Standard 1547 Clause 4.1.7 and the Distribution

System Code (DSC) Appendix F.2 Section 1), the disconnect or isolation device

must:

be a Load Break Switch (capable of interrupting maximum rated load)

be readily accessible by Hydro One

be lockable

have no keyed interlocks

be Gang Operated (for three phase installations)

be a Visible Break type

be of appropriate rating

be located between the Hydro One system and the DG Facility

bear warning to the effect that inside parts can be energized when

disconnecting means is open

be motorized (single phase DG installations exempt)

have a manual override

be required to disconnect the DG facility from HONI‘s distribution system

on a breaker fail condition (protection interface for tripping)

meet all applicable standards and codes (Canadian Electrical Code Part

1 and Part 2)

be capable of being closed onto a fault with complete safety to the

operator – Must not be a source of injury during operation, even when

closed into a faulted system

be capable of being operated without exposing the operator to any live

parts.

This point of disconnection is required for the purpose of work protection of Hydro

One and DG facility personnel. Switching, tagging and lockout procedures shall be

coordinated with HONI. The DG Owner and HONI will mutually agree to the exact

location of the disconnect switch. This switch must not be located in a locked

facility and where DG facilities have H2S or any other hazardous materials present,

it shall be located outside of the hazardous area.

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If multiple generators are connected at the DG facility, one disconnect switch must

be capable of isolating all of the generators simultaneously. There may be other

means of meeting this requirement and any proposals must be reviewed by HONI.

3.1.5 Voltage

The DG facility shall ensure that the operation of the DG(s) do(es) not have an

objectionable impact on the voltage at the PCC. The DG owner is responsible for

ensuring that the voltage at the PCC is maintained as per CSA Standard CAN3-

C235-83 ―Preferred Voltage Levels for AC Systems, 0 to 50,000V Electric Power

Transmission and Distribution.‖ Voltage variations at the PCC are limited to +/- 6%

of the nominal voltage under normal operating conditions. Voltages at all load

connections along the feeder must be at least at levels prior to the interconnection

of the DG. HONI will define voltage requirements on a case by case basis in the

CIA. HONI operates all voltage regulating devices on its distribution system to

125V ±1.5V on a 120V base. The introduction of DGs to HONI‘s distribution

system may result in reverse power flow on the feeder. Voltage regulators on

HONI‘s distribution system may require to be upgraded to be capable of handling

reverse flow.

During abnormal conditions, voltage variations may exceed these values. The DG

Facilities must protect themselves from abnormal voltage conditions which the

distribution system is subjected to. These may include voltage transients, sags

and swells caused by lightning, switching, faults, and the loss or switching of

customer loads. Insulation levels and protective equipment must be capable of

withstanding abnormal voltages on HONI‘s distribution system.

The DG should not actively regulate the voltage at the PCC. During normal

operation, the DG must be loaded and unloaded gradually to allow adequate time

for regulating devices on HONI‘s distribution system to respond and avoid

excessive voltage fluctuations.

For DGs connected to HONI‘s 4-wire distribution system, temporary over-voltage

(TOV) that may be caused by the DG facility interconnection should not exceed

125% of nominal system voltage anywhere on the distribution system and under

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no circumstance shall exceed 130%. HONI will advise on action to reduce TOV to

limits.

For power quality parameters such as voltage dip and flicker requirements, see the

Performance Requirements section (Section 3.4).

3.1.6 Voltage and Current Unbalance

Voltage and current unbalance are normal on many distribution feeders as they

supply many single phase loads and thereby all three phases are never equally

loaded. Phase voltage unbalance of 2% and phase current unbalance of 10-20%

of total feeder load is common. Unbalanced loads that result in unbalanced phase

voltages and currents can cause high neutral currents, negative sequence

voltages and currents, zero sequence voltages, thermal overloading of

transformers and 3-phase motors, and can cause protective relaying to mis-

operate.

To protect HONI‘s distribution system and customers, the DG facility must not

further deteriorate existing unbalance conditions at the PCC and the distribution

system. The phase-phase voltage unbalance of three phase DGs must not be

greater than 1% as measured with balanced three phase loading and with no load.

The DG facility should also protect itself from highly unbalanced voltages,

especially when connected to HONI‘s distribution system where single phase

reclosing is used. The DG Interconnection Transformer may supply unbalance

current to support the unbalanced load on the feeder. This unbalance current may

be present even if the generator is out of service. The proportion of unbalance

load current from the DG Interconnection Transformer will vary based on feeder

topology, unbalanced loads, voltage and DG location. During abnormal conditions

such as faults and single pole reclosing, the unbalance may be very high (current

unbalance may be significantly higher than 20%) and it is up to the DG owner to

ensure that the DG facilities are protected from damage due to unbalance.

Single phase DGs connected to a single phase of HONI‘s distribution system are

limited in size (kVA rating) due to the potential impact they may have on

distribution system voltage unbalance (see Section 3.1.9 for size limitations). A

single phase generator must not negatively impact the unbalance of the nearest

three-phase distribution system. Single phase generators shall not cause an

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unbalance of greater than 2% when connected alone. If multiple single phase

generators are installed, they shall be connected so that an equal amount of

generation is applied to each single phase of the distribution line, and this balance

must be maintained if one or more of the generating units go offline.

3.1.7 Frequency

The generators at the DG facility must operate at a nominal frequency of 60Hz.

They must remain synchronously connected for the frequency range presented

below in Table 2. For any frequencies beyond those presented in the table, the

generator is required to trip instantaneously (see Section 3.2.13) and islanding of

DGs connected to HONI‘s distribution system is not allowed at this time.

Table 2: Operating Frequency Range

Generator Size Frequency Range (Hz)

Low Range High Range

≤ 30 kW 59.3 60.5

≥ 30 kW 57.0-59.8 (adjustable set

point) 60.5

* Source: IEEE 1547

3.1.8 Power Factor

The DG facility shall be capable of operating in the preferred power factor range as

specified by HONI, which is typically in the range of 0.9 lag to 0.95 lead. If

warranted by local distribution system conditions (such as disturbing the

distribution system voltage at the PCC), this range could be narrower or wider and

will be specified by HONI. Field settable and fixed dynamic power factor correction

techniques may be required. Induction generators consume reactive power and

the DG Owner may be required to provide reactive power compensation to correct

the power factor at the PCC. Inverters and static power converters must be able to

adjust their power factor in the range of at least ± 0.90 at the PCC.

For DG facilities that are IESO-impactive (Class 4 DGs), the reactive power

compensation at the generator units should be sufficient so as not to cause any

material increase in the reactive power requirements at the transmission system

transformer station due to the operation of the DGs at all load conditions on the

feeder.

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3.1.9 Capacity Limitations on Generator Interconnections

Distribution feeders operating at nominal voltage levels of 13 kV or higher are

normally supplied from TS‘s or HVDS‘s. The actual loading for all sections of these

types of feeders shall be based on the thermal loading limits corresponding to the

specific conductor sizes as well as the actual ratings of other series elements (line

switches, regulators, distribution transformers, fuses, etc.) but shall not exceed 400

amps. Distribution feeders operating at nominal voltage levels below 13 kV are

normally supplied from DS‘s. The actual loading for all sections of these types of

feeders shall be based on the thermal loading limits corresponding to the specific

conductor sizes as well as the actual ratings of other series elements (line

switches, regulators, distribution transformers, fuses etc.) but shall not exceed 200

amps.

During emergencies and planned outages, the DG facility is required to be

removed if the source (normal feed) is changed over to an alternate source.

The following is a guide for the acceptable total generation limits for feeders

operating at standard Hydro One nominal voltage levels of ≤ 13kV, 13.8 kV, 25 kV,

27.6 kV and 44 kV. Please note that the actual acceptable generation limits for

feeders are determined from detailed connection impact assessments.

3.1.9.1 Three Phase Generator Interconnections

Three phase DGs connecting to HONI‘s distribution at nominal voltage

levels of 25kV, 27.6kV, and 44kV usually do not exceed 10MW. If the

27.6kV feeder is supplied via a 44kV:27.6kV step-down transformer, the

DG facility will be limited to 5MW per individual connection.

Three phase DGs connecting at lower voltage levels (below 15kV) are

normally supplied by HONI‘s distribution stations. The individual generation

limits of DGs connecting to these feeders shall not exceed 1.0MW.

3.1.9.2 Single Phase Generator Interconnections

Individual single phase generators connecting to feeders operating at

nominal voltage levels of 13.8kV, 25kV, 27.6kV and 44kV are limited to

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150kW output. Single phase generators connecting to feeders operating at

nominal voltage levels less than 13kV are limited to 100kW.

3.1.10 Phasing Requirements

HONI and the DG Owner shall agree upon the phase sequence and direction of

rotation. The DG must connect rotating machines as required to establish correct

rotation.

3.1.11 Interconnection Transformer Configuration

As per the DSC, Appendix F.2 Section 2, the interconnection transformer shall not

cause voltage disturbances or disrupt co-ordination of distribution system ground

fault protection. Annex C of CSA Standard C22.3 No.9-08 discusses different DG

interconnection transformer configurations and presents each ones advantages

and disadvantages.

Since the winding configuration of any three phase transformer(s) between the DG

and HONI will have an impact on the distribution system, both under steady state

and fault conditions, Hydro One Networks has analyzed the different options and

has standardized the DG interconnection transformer configuration. This section

will describe the allowable transformer configurations for the interconnection of

DG‘s to HONI‘s 3-Wire and 4-Wire distribution system. Written approval from

HONI will be required for any alternate configuration. The DG Interconnection

Transformer may supply unbalance current to support the unbalanced load on the

feeder. This unbalance current may be present even if the generator is out of

service. The proportion of unbalance load current from the DG Interconnection

Transformer will vary based on feeder topology, unbalanced loads, voltage and

DG location

This directive applies to all DGs connected directly or indirectly (through a hybrid

feeder) to the HONI distribution system and applies to Class 1, Class 2, Class 3,

and Class 4 generators. Where the DG is connected indirectly to HONI‘s

Transmission or Distribution system through an LDC, HONI will assess the impacts

of the connection to the HONI system.

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3.1.11.1 DG Interconnection to 4-Wire Distribution System

Preferred Option HONI‘s preferred transformer interconnection configuration and grounding

for 4-wire distribution systems is shown below in Figure 2, Wye-

Ground:Delta. This configuration will eliminate the damaging TOV

associated with high side delta transformer configurations. A neutral

reactor in the primary winding may be necessary to limit the ground short

circuit current.

Sizing of Neutral Reactor for Conventional (Rotating) Generators

The neutral reactor, Xn shall be sized by the DG Owner and reviewed

during the Connection Impact Assessment based on a Thevenin

Equivalent of the Positive and Zero Sequence Reactance of the DG

facility (example: at the Point of Connection with the Point of

Connection OPEN) that will result in:

1.5 ≤XDG 0

XDG 1≤ 2.5

to achieve an overall Thevenin Equivalent Positive and Zero Sequence

impedance at any point on the feeder with any or all DG sources and

HONI sources In-Service of:

2 <X0

X1 < 3 and

R0X1

< 1

Sizing of Neutral Reactor for DGs with an Inverter Interface



Equivalent of the Zero Sequence Reactance of the DG facility

(example: at the Point of Connection with the Point of Connection

OPEN) that will result in:

X0 = 0.6 ± 10% p. u. and X0

R0 ≥ 4

where 1 p.u. is based on the MVA and high side kV rating of the DGIT.

Note: DGIT MVA rating assumed to be approximately equal to the

generation capacity. See Appendix B for calculation examples.

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Utilizing this DG interconnection transformer (DGIT) winding configuration

and grounding scheme limits the harmful temporary overvoltages on

HONI‘s distribution system, however, it adds a ground source and can

desensitize HONI‘s protective equipment. Once HONI‘s feeder Low Set

instantaneous protection operates, the DGITs along with the generators

shall be tripped off using a HVI, which is required for all DGs connected via

this transformer configuration (refer to Section 3.1.12 and 3.2.6), as seen in

Figure 2. This disconnects the DG facilities DGITs including any ground

sources, allowing the timed overcurrent protection on HONI‘s distribution

system, such as feeder breaker, inline reclosers, and fuses, to detect all

faults on HONI‘s distribution system and coordinate properly. Please refer

to Section 2.9 for an explanation of HONI‘s distribution system protection

scheme.

This DGIT configuration may require a grounding transformer (zig-zag) to

be connected on the LV side of the DGIT if the DG facility needs to limit the

TOV on the LV side. The ground of the DGIT shall be connected to HONI‘s

neutral conductor and the design of the DG facility shall conform to the

grounding requirements set in Section 3.1.14.

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Figure 2: Preferred DGIT Configuration for 4-Wire Distribution Systems

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Alternate Option #1 An alternate DG interconnection transformer configuration for 4-wire

distribution systems is shown in Figure 3. A Wye-ground:Wye-ground

transformer configuration is a viable alternative, however, it is required to

have a delta tertiary winding to limit the harmonic distortion to HONI‘s

distribution system and to limit the TOV‘s on HONI‘s distribution system due

to the introduction of the DG on the feeder if the generator is ungrounded or

high impedance grounded.

Sizing of Neutral Reactor for Conventional (Rotating) Generators






1.5 ≤XDG 0

XDG 1≤ 2.5




2 <X0

X1 < 3 and

R0X1

< 1

Sizing of Neutral Reactor for DGs with an Inverter Interface



Equivalent of the Zero Sequence Reactance of the DG facility

(example: at the Point of Connection with the Point of Connection

OPEN) that will result in:

X0 = 0.6 ± 10% p. u. and X0

R0 ≥ 4

where 1 p.u. is based on the MVA and high side kV rating of the DGIT.



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This alternate DGIT configuration will eliminate the need for grounding

transformers on both the HV and LV side of the DGIT. The ground of the

DGIT shall be connected to HONI‘s neutral conductor (as shown in Figure

3) and the design of the DG facility shall conform to the grounding

requirements set in Section 3.1.14. An HVI will be required as per Section

3.1.12.1.

Figure 3: Alternate DGIT Configuration for 4-Wire Distribution Systems

Rev 0 February 2009


37

Alternate Option #2 DG installations which utilize multiple transformers that step up the voltage

directly to the distribution voltage level and connect to HONI distribution

system through a common PCC may be connected as shown in Figure 4.

The transformers at these generators may be connected delta on the high

side depending on the manufacturer, and in order to facilitate

interconnection of these projects, this alternative transformer configuration

can be used.

This alternative may also be used for inverter based DGs whenever it is

more economical to use grounding transformers as opposed to neutral

reactors due to the impedance required (Refer to Section 3.1.14,

Grounding Requirements).

This alternative will require a grounding transformer (zig-zag) to be

connected on the HV side of the DGITs to limit the TOV on HONI‘s

distribution system. This grounding transformer shall be sized by the DG

Owner and reviewed during the Connection Impact Assessment.

Sizing of Grounding Transformer for Conventional (Rotating) DGs

The grounding transformer shall be sized based on a Thevenin




1.5 ≤XDG 0

XDG 1≤ 2.5




2 <X0

X1 < 3 and

R0X1

< 1

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Sizing of Grounding Transformer for DGs with an Inverter Interface

The grounding transformer shall be sized by the DG Owner and

reviewed during the Connection Impact Assessment based on a

Thevenin Equivalent of the Zero Sequence Reactance of the DG



X0 = 0.6 ± 10% p. u. and X0

R0 ≥ 4

where 1 p.u. is based on the total MVA rating of the DG Facility (sum of

DGITs MVA ratings) and high side kV rating of the DGIT(s). Note:

DGIT MVA rating assumed to be approximately equal to the generation

capacity. See Appendix B for calculation examples.

The grounding transformer shall be located on the DG side of the HVI –

Refer to Section 3.1.12.1 for HVI requirements. The design should be a

padmount zig-zag transformer installed in accordance to all applicable

codes and standards. It shall be solidly connected (not fused) to ensure

that the transformer is in service at all times. The grounding transformer‘s

ground shall be connected to HONI‘s neutral conductor and the design of

the DG facility shall conform to the grounding requirements set out in

Section 3.1.14.

Rev 0 February 2009


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Figure 4: Alternate #2 DGIT configuration

Alternate Option #3 – Available for Installations < 1 MVA HONI‘s preferred transformer interconnection configuration and grounding

for 4-wire distribution systems has been shown in Figure 2. The following

alternate option shown here in Figure 5 may be allowed in certain cases for

small DGs with an aggregate capacity of less than 1 MVA.

In the presence of single phase reclosing upstream of the DG on HONI‘s

distribution system, consideration should be given to use 3 separate single

phase transformers, as this will eliminate the problems associated with

backfeed onto faulted phases due to a shared magnetic core. Therefore in

the case of a downed conductor, without the presence of a HVI at the DG

Rev 0 February 2009


40

facility to disconnect the transformer, the public would not be put at risk due

to magnetically coupled voltage on the conductor.

This configuration passes harmonics readily and as such, the DG Owner

must ensure that harmonic contributions from the facility are within limits,

otherwise mitigation will be required. A neutral reactor in the primary

winding may be necessary to limit the ground short circuit current and will

be determined in the CIA. The neutral reactor, if needed, shall be sized as

in the preferred option.

Figure 5: Alternate DGIT configuration for facilities < 1 MVA

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41

3.1.11.2 DG Interconnection to 3-Wire Distribution System

Preferred Option HONI‘s preferred DG interconnection transformer configuration and

grounding for 3-wire distribution systems is shown below in Figure 6, Delta:

Wye-ground. HONI‘s 3-Wire Distribution Systems have been designed to

withstand phase to phase voltages and thus there is no concern of TOV for

these connections. Since TOV is not a problem, HONI prefers this option

as it does not introduce additional ground sources to HONI‘s distribution

system. The requirement for having an HVI installed at the DG facility may

be waived.

If the HVI requirement is waived, the DG Owner shall decide whether or not

to install an HVI. If in the future the requirements change, and the HVI is

required, the DG Owner will be obliged to install one at its own cost. An

LVI (Low Voltage Interrupter on the generator side of the DGIT) will be

required if an HVI is not installed. The design of the DG facility shall take

into consideration the possibility of ferroresonance due to the loss of one or

two phases and shall take steps to ensure that the DG facility is protected

under such an occurrence.

Protection systems shall be designed accordingly to ensure that ground

faults on HONI‘s distribution system are detected.

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Figure 6: Preferred DGIT Configuration for 3-Wire Distribution System

Alternate Option #1 A Wye-Ground:Delta DG interconnection transformer on HONI‘s 3-Wire

distribution system as shown in Figure 7 is not a preferred option, however

it may be acceptable if required and will be determined in the CIA. A

neutral reactor in the primary winding may be necessary to minimize the

ground source current and should be sized such that TOV is limited to a

ceiling of 150% of nominal voltage. Due to the addition of a ground source

to HONI‘s distribution system, an HVI will be required. This DGIT

configuration may require a grounding transformer (zig-zag) to be

connected on the LV side of the DGIT to limit the TOV on the LV side.

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Figure 7: Alternate DGIT configuration for 3-Wire Distribution System

Alternate Option #2

A Wye-ground:Wye-ground interconnection transformer on HONI‘s 3-Wire

distribution system as shown below in Figure 8 is also not a preferred

option, however it may be acceptable if required and will be determined in

the CIA. It is required to have a delta tertiary winding to limit the harmonic

distortion to HONI‘s distribution system.

A neutral reactor in the primary winding may be necessary and should be

sized such that TOV is limited to a ceiling of 150% of nominal voltage.

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44

Figure 8: Alternate DGIT configuration for 3-Wire Distribution System

3.1.12 High Voltage Interrupting Device (HVI)

The following are requirements for a HVI to be installed at the DG facility. This

device shall be sized properly to account for present and future anticipated fault

levels. The design shall be reviewed and accepted by HONI. If an HVI is not

required, a Low Voltage Interrupter (LVI) shall be installed on the low voltage side

of the DGIT.

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45

3.1.12.1 Requirement for Interconnection to 4-Wire Distribution System

A High Voltage Interrupter (HVI) with protection interface for tripping is

required for all DGs larger than 1 MVA connected to HONI‘s 4-wire

distribution system. This is required to remove the ground source (see

Section 3.1.11.1 for DG Interconnection Transformer Configuration) from

the distribution network following a fault to allow for proper protection

coordination. For DGs smaller than 1 MVA connecting through a Wye-

ground:Wye-ground DGIT, the HVI is optional (see Section 3.1.11.1,

Alternate #3).

3.1.12.2 Requirement for Interconnection to 3-Wire Distribution System

If the DG Interconnection Transformer preferred option (Section 3.1.11.2) is

chosen for HONI‘s 3-wire system, the HVI is optional, and the DG Owner

shall decide whether to install an HVI or not. If in the future, the

requirements change and an HVI will be required, the DG Owner will be

obliged to install one at its own cost. For all other alternate options for the

DG Interconnection transformer for HONI‘s 3-Wire distribution System, an

HVI will be required for DG Facilities.

3.1.12.3 Interrupting Time Requirement

When the HVI is the used to disconnect generation from HONI‘s distribution

system, it must not exceed the maximum interrupting time of 85ms (5

cycles).

3.1.13 Station Service for Critical Loads

A dedicated station service AC power source will be required to supply critical

loads (such as the station battery) whenever the HVI or LVI are OPEN. If the

station service AC service power source is obtained from either HONI or a local

distribution company, the DG owner must ensure that the above station service AC

power source cannot be electrically connected to the DG electrical system that is

associated with the power transfer from the DG facility to the HONI distribution

system (example: the intent is to prevent reverse power from the DG facility to the

station service AC supply source. The station service load shall not impose

operating restrictions on HONI‘s system when either the Motorized Disconnect

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46

Switch (Load Break Switch) or the HVI is opened – generator is disconnected.

The station service shall comply with all required load connection standards.

3.1.14 Grounding

The DG facilities grounding (generators and interconnection) shall be per

manufacturer‘s recommendation and the OESC and follow the requirements set

out in this document (refer to Section 3.1.11, Interconnection Transformer

Configuration and Section 3.2, Protection requirements section).

The grounding of the DG facility must not cause overvoltages that exceed the

rating of equipment connected to HONI‘s distribution system. Refer to Section

3.1.5 for voltage requirements). The grounding of the DG facility must not disrupt

the coordination of ground fault protection of Hydro One‘s distribution system.

As discussed in Section 3.1.11, if the primary HV winding of the DG

Interconnection Transformer is grounded, the ground grid of the DG facility is to be

connected to HONI‘s ground grid (neutral). For 4-wire DG installations,

transformers configured Wye-Gnd:Δ or Wye-Gnd:Δ:Wye-Gnd (refer to Section

3.1.11 for allowable DG Interconnection Transformer configurations) may require a

neutral reactor or a grounding transformer. The reactor or grounding transformer

shall be sized as follows:

Sizing of Neutral Reactor and Grounding Transformer for Conventional

(Rotating) Generators

The neutral reactor, Xn or grounding transformer shall be sized by the

DG Owner and reviewed during the Connection Impact Assessment

based on a Thevenin Equivalent of the Positive and Zero Sequence

Reactance of the DG facility (example: at the Point of Connection with

the Point of Connection OPEN) that will result in:

1.5 ≤XDG 0

XDG 1≤ 2.5




2 <X0

X1 < 3 and

R0X1

< 1

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Sizing of Neutral Reactor or Grounding Transformer for DGs with an

Inverter Interface

The neutral reactor, Xn or grounding transformer shall be sized by the

DG Owner and reviewed during the Connection Impact Assessment

based on a Thevenin Equivalent of the Zero Sequence Reactance of

the DG facility (example: at the Point of Connection with the Point of


X0 = 0.6 ± 10% p. u. and X0

R0 ≥ 4

where 1 p.u. is based on:

the total MVA rating of the DG Facility (sum of DGITs MVA

ratings) and high side kV rating of the DGIT(s) for Grounding

Transformer sizing.

the MVA and high side kV rating of the DGIT for Neutral

Reactors sizing.



For 3-wire installations, where the same transformer configuration is chosen, the

reactor shall be chosen to provide a TOV ceiling of 150% nominal voltage.

In wind farm installations, to limit the exposure of lightning to HONI‘s distribution

system, the lightning protection at each wind tower must be electrically separated

from the DG facility – Ground grids of wind towers shall be separated from the DG

Station ground grid. This can be achieved by ensuring that the wind towers are

not bonded to the stations electrical grid.

The installation of a wind farm shall not increase the lightning transfer to HONI‘s

system. Stand alone studies are required to ensure that GPR meets step and

touch potential ESA requirements and must also be submitted to HONI.

Design Consideration

Ground grids of wind towers shall be separated from the DG Station ground

grid. This can be achieved by ensuring that the wind towers are not bonded to

Rev 0 February 2009


48

the stations electrical grid. There are different ways to achieve this, such as

ensuring that the cables are not bonding the two systems together (can be

achieved by designing a span or section of the line overhead).

3.1.15 Fault Levels

The impact of DG interconnection facilities on existing equipment ratings, circuit

loading and fault levels must be assessed. X/R ratios and maximum short circuit

levels must be maintained within acceptable Distribution System design and

Transmission System Code (TSC) limits. The DG facilities must not increase the

fault levels beyond these limits. Any required changes to distribution system

equipment ratings must be assessed by Hydro One and paid for by the DG Owner.

3.1.16 Resonance Analysis

The design of the DG facility should include a careful examination of resonance.

Resonance can cause damage to HONI‘s distribution system, electrical equipment

of HONI‘s customers, and the electrical equipment at the DG facility. Analysis

should be conducted by the DG owner to evaluate the possibility of the following

resonance conditions and if there is a possibility of them, eliminate their harmful

effects:

Ferro-resonance in the transformer – operating information may be

provided to the DG Owner upon request (information on single phasing

possibilities)

Sub-synchronous resonance due to large rotating machines and/or

capacitor banks present on the distribution system

Harmonic resonance with other customer‘s equipment when capacitors

are added to HONI‘s distribution system

Information on HONI‘s distribution system for the purpose of this analysis can be

provided upon request. Resonance analysis should be submitted to HONI for

evaluation and review.

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3.1.17 Self-Excitation Analysis

If the DG being installed is an induction generator, studies shall be conducted to

assess whether there is a possibility of self-excitation. Information on HONI‘s

distribution system for the purpose of this analysis can be provided upon request.

Self-excitation analysis should be submitted to HONI for evaluation and review.

3.1.18 Islanding

Upon loss of voltage in one or more phases of the HONI distribution system, the

DG facility shall automatically disconnect from all of HONI‘s distribution line

ungrounded conductors prior to the reclosure of HONI protection equipment. Local

islanding detection is required and will be discussed in Section 3.2.15.

Intentional islanding is not allowed at this time.

3.1.19 Synchronization

The DG facility shall parallel with HONI‘s distribution system without causing a

voltage fluctuation at the PCC greater than ± 4% of the prevailing voltage level of

the distribution system at the PCC and meet the flicker requirements (Section

3.4.1.1).

The DG facility (synchronous and permanent magnet generators) shall remain in

synchronism with HONI‘s distribution system while operating in parallel to HONI‘s

distribution system. Synchronous generators, self-excited induction generators or

inverter-based generators that produce fundamental voltage before the paralleling

device is closed can only parallel with HONI‘s distribution system when frequency,

voltage, and phase angle differences are within the ranges given below in Table 3

at the moment of synchronization. For synchronous generators, an approved

automatic synchronization device is required if the plant is unattended (IEEE

device number 25) to ensure that the DG facility will not connect to an energized

feeder out of synchronism.

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Table 3: Resynchronization Requirements

Aggregate Rating of Generators

(kVA)

Frequency Difference

(Δ f, Hz)

Voltage Difference

(Δ V, %)

Phase Angle Difference

(̊Δ Φ, ̊ )

0-500 0.3 10 20

>500 – 1500 0.2 5 15

>1500 0.1 3 10 * Source: IEEE 1547

Induction generators and inverter-based generators that do not produce

fundamental voltage before the paralleling device is closed, and double-fed

generators whose excitation is precisely controlled by power electronics to produce

a voltage with magnitude, phase angle, and frequency that match those of the

distribution system may not require synchronization facilities. These types of

generators shall be tested to determine the maximum startup current. The results

shall be used, along with the Distribution System source impedance for the

proposed location, to estimate the starting voltage magnitude change and verify

that the unit will not cause a voltage fluctuation at the PCC greater than ± 4% of

the prevailing voltage level of the distribution system at the PCC and meet the

flicker requirements (Section 3.4.1.1). Induction generators may be connected and

brought up to synchronous speed by direct application of rated voltage provided

that they meet the requirement of voltage drop given above and/or they do not

exceed flicker limits at the PCC. Otherwise, other methods such as reduced

voltage starting or speed matching using the prime mover prior to connection must

be used to respect these voltage drop and flicker limits.

Any proposed synchronizing scheme must be submitted to HONI prior to

installation and must be able to accommodate automatic reclosing on HONI‘s

distribution facilities. For large DG facilities with multiple generator units,

staggering the generator reconnections to HONI‘s distribution system may be

required and will be coordinated with HONI. Refer to Section 3.2.19, Section

3.2.21 and Section 3.2.23 for further information.

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3.1.20 Insulation Coordination

The DG facility shall be protected against lightning and switching surges such as

voltage stresses. Temporary overvoltages may affect equipment, both on the

distribution system and the DG facility. Overvoltage protection usually includes

using station and line shielding against direct lightning strikes and surge arresters

for all wound equipment. The surge arresters are located as close as possible to

the equipment they protect. HONI‘s distribution system voltage ratings are shown

below in Table 4.

Table 4: Arrester Ratings

HONI Distribution System Voltage Arrester

MCOV Rating

System Phase

Voltage (kV)

Arrester MCOV (kV)

4.16 3

8.32 6

12.5 9

13.8 10

24.9 18

27.6 21

44 39 (intermediate

class)

3.1.21 Equipment Rating and Requirements

The generation facility interface equipment must be compatible with Hydro One

equipment design and ratings under all operating conditions. Considerations

include, but are not limited to:

Respecting equipment thermal loading limits

Impact of generation facility fault contribution on equipment rating

If power is able to flow in reverse direction, then all existing voltage

regulating and metering devices must be suitable for bi-directional flow.

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3.1.22 Operating Requirements

The following are a list of operating requirements for DGs interconnecting to Hydro

One Networks Inc. sub-transmission and distribution system:

Switching that involves manual operation of air break switches will

require all connected DG's to come off-line as directed by the

Connection Agreement and/or Controlling Authority.

Any source configuration which is not the ―normal‖ source will require all

DGs to be disconnected until such a time when the ―normal‖ supply has

been restored. Normal supply is defined as the supply configuration that

has been studied in the CIA.

Any temporary feeder parallels will require all connected DG's to come

off-line as directed by the OGCC.

Transfer Trip and DGEO communications required for DGs 1 MVA and

larger, connecting to HONI‘s distribution system at voltages greater than

20 kV.

Transfer Trip initiated for outages upstream of the feeder breaker must

be in place back to the generator (i.e. high side faults, bus differential).

For feeders with multiple feeder reclosers, 50% minimum feeder load

calculations shall identify remaining loading levels with reclosers in open

position.

No automatic reconnection to the system will be allowed unless:

There is always customer contact with the ability to immediately

disconnect from the system if requested by the OGCC (24 hours/7

days per week, or

OGCC has the ability to remotely disconnect DG customer from

the system, and

Feeder relay studies must be updated if circuit configuration is

materially altered. If the source changes from the configuration

studied in the CIA, the generator will not be allowed to reconnect.

Automatic Reconnection to HONI‘s distribution system shall be locked

out once voltage and frequency are not within operating ranges for a

period of 15 minutes on any phase

Legacy facilities need to meet this documents DG Requirements.

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3.1.23 Metering

Metering requirements vary with the type and intent of the generation facility.

Please consult the IESO Market Rules and the Distribution System Code Section 5

for details. Refer to Section 4 of this document for more information.

3.1.24 DG Facility Acceptance

The DG facility interconnecting to HONI‘s distribution system must have a

professional engineer licensed in the Province of Ontario declare (stamp and seal)

that the DG facility has been designed, tested and constructed in accordance with

the requirements of this document, HONI‘s site-specific requirements, prudent

utility practice and all applicable standards and codes. HONI shall receive and

review all designs from the DG Owner at the proper stage.

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3.2 Protection Requirements

3.2.1 General Requirements

Abnormal conditions in the DG facility and on HONI‘s distribution system require

that the DG facility respond and protect itself and HONI‘s distribution system. This

response contributes to the safety of HONI‘s and DG‘s personnel and the general

public and avoids damage to both DG facility‘s, HONI‘s and HONI‘s customer‘s

equipment.

The protection schemes shall be designed to detect the conditions presented in

this section of this requirements document including but not limited to:

Balanced and unbalanced faults (line to ground, line to line, three phase)

at the DG facility and HONI‘s distribution system (entire distribution

feeder that DG is connected to)

Abnormal frequencies

Abnormal voltages

Islanding Conditions

The protection schemes employed shall coordinate with HONI‘s distribution system

protections and shall be designed for current and anticipated future fault levels.

Dedicated communications may be required to facilitate timely clearing of faults.

All protection operations shall ensure that the generator(s) and all sources of

ground current are tripped within the required time from the start of the

disturbance. For DG facilities utilizing a Wye-Ground high side DG Interconnection

Transformer (refer to Section 3.1.11 Interconnection Transformer Configuration),

both the DGIT and the generators must be tripped within the required clearing time

(refer to Section 3.2.4).

All protection scheme proposals will need to be reviewed and accepted by Hydro

One Networks Inc.

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3.2.2 Hydro One Networks Inc. Distribution System Feeder Protection

HONI will provide to the DG Owner, upon request, all applicable information about

HONI‘s distribution system protection scheme on the feeder interconnecting with

the DG facility.

Information regarding HONI‘s protection system, including philosophy, can be

found in greater detail in Section 2.9

HONI‘s distribution system protections may need to be upgraded and/or replaced

to accommodate DG interconnections. This may have financial implications for the

DG Owner.

3.2.3 Sensitivity and Coordination

The DG facilities protection shall provide adequate sensitivity to detect and clear

all faults in the DG facility as well as HONI‘s distribution system. The design shall

coordinate with other HONI protection system devices at present and anticipated

future fault levels.

3.2.4 Protection Operating Times

The DG interconnection protection shall disconnect the DG facility from HONI‘s

distribution system within the required time as specified in the individual

requirements throughout this document – Example: For any phase and ground

faults a maximum of 500ms from inception of the fault condition and islanding

conditions. This time is measured from the start of the abnormal condition to the

time the DG will cease energizing HONI‘s distribution system. This is a maximum

clearing time and in certain instances, the clearing time may be more stringent.

HONI will determine this in the CIA.

Timing diagrams for different events are shown for reference in Appendix C.

If the DG facility is required to have a High Voltage Interrupter (refer to Section

3.1.12), there is a requirement to ensure that the DG Interconnection Transformer

is disconnected from HONI‘s distribution system under abnormal conditions.

Therefore, the protections shall trip both the generators and HVI and clear within

the required time. Refer to Section 3.2.20, ―Disconnection of DG Facilities‖, and

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Section 3.2.21, ―Reconnection to Hydro One Network‘s System‖, for more

information.

3.2.4.1 Interrupting Time for Device Disconnecting Generation

The interrupting device used to disconnect generation from HONI‘s

distribution system must have maximum opening time of 85ms.

3.2.5 Interrupting Device Rating

All fault current interrupting devices shall be sized appropriately. Fault contribution

from both the DG facility and HONI‘s distribution system shall be used to

adequately size all fault current interrupting devices. HONI will provide present

and anticipated future fault contribution levels from HONI‘s distribution system.

The interrupting device used to disconnect generation from HONI‘s distribution

system must have maximum interrupting time of 85ms.

For DGs that have a time variant fault contribution characteristics, the

characteristics producing the highest fundamental component fault current shall be

used – synchronous and induction generators shall use sub transient reactance to

calculate fault contribution. Inverter based DGs typically contribute fault current

marginally higher than rated full load current (usually 1.2 to 1.5 times the rated

load current of the inverter for self-commutated designs and less for line-

commutated inverters). Depending on the design, the rotor of double-fed

asynchronous motors may be shorted by crowbar action in response to severe

faults causing the generator to behave like an induction generator.

3.2.6 High Voltage Interrupter (HVI)

NOTE: For the purpose of this document, the HVI will refer to interrupting devices

on HONI‘s side of the DG Interconnection Transformer – whether it is high voltage

or medium voltage.

DG facilities connecting on 4-Wire distribution systems are required to be equipped

with a High Voltage Interrupter (HVI) as can be seen in Figure 2, Figure 3, and

Figure 4 of Section 3.1.11.1. For DGs smaller than 1 MVA connecting through a

Wye-ground:Wye-ground DGIT, the HVI is optional (see Section 3.1.11.1,

Alternate #3).

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DG facilities connecting on 3-Wire distribution systems are not required to be

equipped with a High Voltage Interrupter (HVI) if they connect using the preferred

DGIT configuration (Refer to Section 3.1.11.2). All ―Alternate‖ DGIT configurations

for 3-Wire connections require an HVI.

In the event that an HVI is required, it will be equipped with a protection interface

for Tripping. The HVI shall be sized according to the present and future

anticipated fault current. The HVI status should be monitored and ―Breaker Fail‖

initiated during every protection trip operation – See Section 3.2.7 for details on

Breaker Fail.

This requirement is driven by the DG Interconnection Transformer Configuration

and the need to remove the ground source from the distribution system before the

1st reclose to ensure that the DG facilities will not adversely affect overcurrent

protection devices on HONI‘s distribution system - the feeder and DG HVI will be

tripped for feeder faults or feeder islanding conditions (feeder breaker trips

instantaneously and independently of DG HVI tripping). Before the 1st reclose, all

the DGs and associated DGITs on the distribution feeder shall be disconnected

from the feeder. Upon reclose, the feeder 51 & 51N times overcurrent devices will

co-ordinate with reclosers and lateral fuses on HONI‘s distribution system since all

current infeeds from the DGs and DGITs are removed. The HVI is also required to

prevent backfeed whenever single phase switching can occur upstream of the DG

on HONI‘s distribution system Refer to Section 2.9 for more information regarding

HONI‘s distribution system protection practices and standards.

As the HVI trips, the generators shall trip (LVI or equivalent) and the HVI should

reclose back in within the first 30 seconds in the event of a successful reclose

operation on HONI‘s feeder – The first DG facility connected to the feeder shall

have the HVI reclose within 15 seconds of detecting voltage and frequency within

normal limits (refer to Section 2 for details on operating characteristics of HONI‘s

Distribution system). There may be a need to stagger multiple DG‘s DGITs

energization to minimize the effects of inrush on HONI‘s distribution system and

the resulting voltage sag and flicker (additional DG facilities shall be set between

15 seconds and 30 seconds). Refer to Section 3.2.21 for more information on

reconnection to HONI‘s system following a momentary and sustained outage and

Appendix C for timing diagrams.

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3.2.7 Breaker Fail (BF)

* Breaker Fail may refer to a breaker, HVI, LVI or any fault interrupting device failing.

Breaker Fail protection needs to be included in the DG facility‘s protection design

for both the High Voltage Interrupter and Low Voltage Interrupter to ensure that a

breaker/interrupter failure will not disrupt HONI‘s distribution system and/or the DG

facility by ensuring that faults are cleared in a timely fashion. A means of

automatic backup isolation is required to allow quick restoration of the distribution

feeder. The breaker failure protection should have a maximum pickup time delay

after initiation of 0.3s.

3.2.7.1 BF Protection for HVI

The DG facility protections shall provide breaker failure protection and trip

all LV breakers in the event of the HVI or primary interrupting device

failing to isolate the DG facility from HONI‘s distribution system. The

motorized disconnect switch (see requirements in Section 3.1.4) shall be

opened by a separate auxiliary relay in the event of a breaker fail

condition to ensure that the DG facility is properly isolated from HONI‘s

system.

In the case of a circuit switcher, the interrupter and the motorized

disconnect shall be specifically chosen to operate independently. In

normal operation, when the HVI isolates the facility, the motorized

disconnect switch will follow, opening a short period afterwards. It can

also be designed to open sequentially – motorized disconnect opens if

HVI does not OPEN following a trip initiation.

In the event of a breaker fail condition, the next zone at the DG facility will

be tripped via the Low Voltage Interrupter in the facility (LVI) and by

removing the prime mover and excitation system as appropriate. The

motorized disconnect switch (at the PCC) shall be used to automatically

isolate the DG facility from the distribution system. In the event that an

alternate interrupting means (fuses or otherwise) is not provided by the

DG facility or if such alternate interrupting means fail to coordinate with

the opening of the motorized disconnect switch, then the disconnect

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switch may incur significant damage when attempting to interrupt a

sustained fault current condition as it is not rated for breaking fault current.

The design of the DG facility shall take this into consideration when

deciding on a location for the Point of Disconnect to ensure that safety of

the DG facility personnel, HONI‘s personnel and general public will be

ensured.

The design of the BF protection for the HVI shall be submitted to HONI for

review and acceptance.

3.2.7.2 BF Protection for LVI

In the event of the LVI malfunctioning, breaker fail protection is required to

ensure that a fault in the DG facility is cleared and will not affect the high

voltage system. Breaker fail should trip the HVI (and initiate BF on the

HVI) to ensure that the DG facility is isolated from HONI‘s distribution

system. For the DG facilities not equipped with an HVI, the motorized

disconnect switch (Load Break Switch) shall be opened to isolate the DG

facility from HONI‘s distribution system. In the event that an alternate

interrupting means (fuses or otherwise) is not provided by the DG facility

or if such alternate interrupting means fail to coordinate with the opening

of the motorized disconnect switch, then the disconnect switch may incur

significant damage when attempting to interrupt a sustained fault current

condition. The DG Owner shall take steps to ensure that the DG facility,

its equipment and personnel is protected.

3.2.8 Single Phase Generators

Single phase generator requirements are summarized below in Table 5. Inverter

type generators must be compliant with IEEE Std. 929 Recommended Practice for

Utility Interface of PV Systems and be certified to UL 1741 and CSA 22.2-107.1.

Figure 9 shows an example protection for single phase generators given for

information purposes only. The protection system can be designed differently.

The final design of the protection system shall be submitted to HONI for approval

as described in Section 3.2.36.

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Table 5: Typical Protections Required for Single Phase DG Facilities

Protection Description IEEE Device #

Interconnect Disconnect Device 89 Generator Disconnect Device

Over-Voltage Trip 59 Under-Voltage Trip 27

Over Frequency Trip 81O Under Frequency Trip 81U

Overcurrent** 50/51 Distance *** 21

Synchronizing Check* 25 Anti-Islanding Protection Refer to Section 3.2.15

Additional Protections May Be Required

* Only required for synchronous generators and other types which

have standalone capability ** Could be provided by magnetic circuit breaker or fuse *** Distance may be required to be able to detect faults along the

entire length of the feeder

Figure 9: Example Protection for a Single Phase Generator

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3.2.9 Three Phase Generators

Three phase generator typical protection requirements are summarized below in

Table 6. Inverter type generators must be compliant with IEEE Std. 929

Recommended Practice for Utility Interface of PV Systems and be certified to UL

1741 and CSA 22.2-107.1.

Section 3.2.9.1 through to Section 3.2.9.3 (Figure 10-12) shows example

protections for three phase generators depending on the DGIT configuration

chosen for DGs connecting to HONI‘s 3-Wire distribution system. Section 3.2.9.4

through to Section 3.2.9.6 (Figure 13-15) shows example protections for three

phase generators depending on the DGIT configuration chosen for DGs

connecting to HONI‘s 4-Wire distribution system. The protection systems can be

designed differently and the examples shown in this document are for

informational purposes only. Additional protections may be required. Generator

protections are not the focus of this document and no requirements are set by

HONI. It is up to the DG Owner to ensure that the generators are protected

sufficiently. The final design of the protection system shall be submitted to HONI

for approval as described in Section 3.2.36. DG Interface Transformer

Configuration Requirements are located in Section 3.1.11.

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Table 6: Typical Protections for Three Phase DGs

Description Device HONI Distribution

System Protection

Anti-Islanding

Protection

Synchro-nization

DG Protection

X - Required O - Optional

Transfer Trip Receive TTR* X*

DGEO DGEO X*

Over-Voltage Trip 59 X X X X

Under-Voltage Trip 27 X X X X

Over-Frequency Trip 81O X X X X

Under-Frequency Trip 81U X X X X

Overcurrent 51 X X

Neutral Overcurrent 51N X X

Voltage Controlled Overcurrent

51V O O

Directional Overcurrent 67 O O

Directional Neutral Overcurrent

67N O O

Transformer Differential 87 O O Distance 21 O** O

Ground Distance 21N O** O

Ground Overvoltage 59N*** O O

Reverse Power 32 O O O

Negative Sequence Overcurrent

46 O O O

Negative Sequence Voltage

47 O O O

High Speed Overvoltage

59I*** O O

Synchronization Check 25 X

Loss of Excitation 40 O

Interconnection Disconnect Device

89 X X X

Generator Disconnect Device

X

* Transfer Trip and DGEO required where available generation is greater than 50% of minimum load, or where reclosure is less than 1 second, or if DG facility is rated at 1 MVA or higher – Refer to Section 3.2.16

** May be required if complete feeder coverage cannot be guaranteed for entire length of feeder

*** May be required if ferroresonance is expected

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3.2.9.1 Delta:Wye DGIT Connecting to 3-Wire – Preferred

Figure 10: Preferred Connection for 3-Wire Distribution System

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3.2.9.2 Wye-Gnd:Delta DGIT Connecting to 3-Wire - Alternate

Figure 11: Alternate Connection for 3-Wire Distribution System

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3.2.9.3 Wye-Gnd:Delta:Wye-Gnd Connecting to 3-Wire - Alternate


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3.2.9.4 Wye-Gnd:Delta DGIT Connecting to 4-Wire - Preferred

Figure 13: Preferred Connection for 4-Wire Distribution System

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3.2.9.5 Wye-Gnd:Delta:Wye-Gnd Connecting to 4-Wire - Alternate


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3.2.9.6 Delta:Wye DGIT Connecting to 4-Wire - Alternate


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3.2.10 Phase and Ground Fault Protection Requirement

The DG facility‘s protection system must ensure that the DG facility will detect and

automatically isolate itself from HONI‘s distribution system for:

Internal Faults within the DG facility

External Faults within HONI‘s distribution system – the DG must detect

phase and ground faults along the entire distribution feeder that it is

connected to – including single phase lateral taps 2

The DG‘s protections must be capable of detecting the following conditions at the

DG facility and HONI‘s distribution system feeder which it is interconnected with:

Phase-to-Phase faults

Phase-to-Ground faults

Loss of any phase

HONI will provide the DG Owner the maximum impedance fault that the DG facility

is required to detect. The protective device selectivity and sensitivity have to be

maintained over the full range of minimum to maximum fault currents (present and

anticipated future levels) with the DGs infeed.

The total clearing time for faults on HONI’s distribution system or for faults

in the DG facility is to be no more than 500ms to coordinate with HONI’s

reclosure time. The clearing time is measured from the start of the abnormal

condition to the time that the DG facility ceases to energize HONI’s


DG facilities requiring an HVI due to the DGIT winding configuration must ensure

that phase and ground fault protection are always operational as long as the HVI is

closed – ground fault protection must be operational even if generators are out of

service. This is to ensure that the DGIT and resulting ground source will be

disconnected from HONI‘s system in the event of a fault and allow proper

overcurrent coordination.

2 Must see entire feeder for phase and ground faults – past reclosers/sectionalizers/fuses

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A means of automatic backup isolation is required to cater for an HVI or LVI failure

condition. The automatic backup isolation is required to allow quick restoration of

the distribution system feeder following an HVI or LVI failure condition. The

motorized disconnect switch at the PCC shall be used to automatically isolate the

DG Facility from the distribution system. In the event that an alternate interrupting

means (fuses or otherwise) is not provided by the DG Facility or if such alternate

interrupting means fail to coordinate with the opening of the disconnect switch,

then the disconnect switch may incur significant damage when attempting to

interrupt a sustained fault current condition. All breaker fail protection designs

shall be submitted to HONI for review and approval (See requirements in Section

3.2.7).

All protective device settings and protection scheme designs must be submitted to

HONI for review. Over time, as the system configuration changes, settings may be

required to be changed to maintain adequate system protection.


Standard overcurrent elements may not cover faults along the entire feeder

and may not coordinate with HONI‘s protection systems. Distance (21) type

protections may need to be considered. The settings for the distance

elements shall be determined by the DG Owner with the information provided

by HONI. The distance elements will be required to detect faults along the

whole feeder after HONI‘s protections operate and HONI disconnects. It may

be impossible for the DG protections to detect all faults over the whole feeder

prior to HONI disconnecting due to the apparent impedance before HONI‘s

protections trip. Due consideration must be given to apparent impedances

due to other DGs connected to the feeder.

3.2.11 Unbalance Protection

The DG facility is required to detect single phasing conditions (loss of phase) –

Refer to Section 3.2.10.


The design of the DG facility should consider using an unbalance or negative

sequence relay that will trip the DG on excessive current unbalance, especially

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if the DG is installed on a section of HONI‘s distribution system that utilizes

single phase tripping.

3.2.12 Feeder Relay Directioning

Existing overcurrent protections in HONI‘s distribution system have been designed

to clear phase and ground faults downstream of their location as HONI‘s

substation has been the one source feeding the fault. With the addition of DGs to

HONI‘s distribution system (additional sources), the fault contribution from these

DGs may cause HONI‘s protections to operate non-selectively for reverse faults.

Feeder relay overcurrent elements may trip for faults on adjacent feeders due to

the infeed from DGs on the feeder. To prevent this sympathetic tripping, the relays

may need to be directioned to be able to sense reverse fault current conditions.

Inline reclosers may also need to be directioned to ensure that faults upstream of

the reclosers will not cause the reclosers to operate due to the infeed from the

DGs. In addition, communication facilities between the TS and recloser may be

required as a result of DGs located downstream of the recloser to facilitate co-

ordinated tripping and reclosing.

The need to replace/update equipment on HONI‘s distribution system to enable

directioning of feeder protections will be specified to the DG Owner in the CIA.

3.2.13 Over Frequency/Under Frequency Protection

Over and under frequency protection is required at the PCC of the DG

interconnection (see OESC rule 84-014, IEEE Std. 1547 Clause 4.2.4, CSA Std.

C22.3 No.9-08). The DG facility interconnection protection scheme shall have the

capability of detecting abnormal frequencies and clearing within the times shown

below in Table 7. The DG facility must separate from HONI‘s distribution system if

these frequency deviations occur within the clearing time. The clearing time is

measured from the start of the abnormal condition to the time that the DG facility

ceases to energize HONI‘s distribution system. These clearing times are

maximum clearing times and may be required to be more stringent. This

information will be provided by HONI. For generators > 30 kW, the frequency set

points shall be field adjustable while for smaller generators, it may be fixed or field

adjustable.

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For generators > 30 kW, the lower frequency set points shall be set to comply with

the NorthEast Power Coordinating Council (NPCC), ―Directory D2‖, as seen below

in Figure 16 – adjustable Lower Frequency set point shall be set to follow the

attached graph.

The DG may reconnect after the distribution system is stabilized and the

requirements of this guide are met. For additional requirements related to

reconnection to HONI‘s distribution system refer to Section 3.2.21.

Table 7: Over/Under Frequency Protection Set Points and Clearing Times

Generator Size Frequency Range (Hz) Clearing Times(s)*

≤ 30 kW > 60.5 0.16 < 59.3 0.16

> 30 kW

> 60.5 0.16 < (59.8 – 57.0) -

adjustable Adjustable – 0.166

to 300 < 57.0 0.16

* Generators ≤ 30kW – Maximum clearing time Source: IEEE 1547

* Generators > 30kW – Default clearing time

Figure 16: NPCC Directory D2 Requirement

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3.2.14 Overvoltage/Undervoltage Protection

Over and under voltage protection is required at the DG facility PCC (IEEE Std.

1547 Clause 4.2.3, DSC Appendix F.2 Section 6.5, CSA C22.3 No.9-08 Clause

7.4.7). The DG facility interconnection protection scheme shall have the capability

of detecting abnormal voltages shown in Table 8 and disconnecting the DG facility

from HONI‘s distribution system in the clearing times specified (voltage is to be

measured phase-neutral for single phase installations or grounded Wye-Wye

transformer configurations, otherwise phase-phase voltage shall be used). The

voltages shall be detected at the PCC.

The clearing time is measured from the start of the abnormal condition and the DG

facility ceasing to energize HONI‘s distribution system. These are maximum

clearing times and may be more stringent depending on the application. HONI will

provide these clearing times if different from the table. For DGs > 30kW, the

voltage set point shall be field adjustable and for smaller DGs, it can be fixed or

field adjustable. Undervoltage relays should be time-delayed to avoid

unnecessary tripping while over-voltage relays may be instantaneous. High speed

instantaneous voltage protection may be considered for detecting ferroresonance

and self-excitation conditions.

Table 8: Over/Under Voltage Protection Setting and Clearing Time

Voltage Range (% of base voltage) Clearing Time(s)*

V < 50 0.16 50 ≤ V < 88 2.00

110 < V < 120 1.00 V ≥ 120 0.16

* DG ≤ 30 kW – Maximum clearing time Source: IEEE 1547 * DG > 30 kW – Normal clearing time

The DG facility may reconnect after HONI‘s distribution system has stabilized and

requirements for reconnection in this document are met (refer to Section 3.2.21).

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3.2.15 Anti-Islanding Protection

An electric island is a section of the distribution system which, when disconnected

from the rest of the HONI system, remains energized by DGs connected to the

feeders. Anti-islanding protection is required to:

Ensure that HONI customers do not experience power quality problems

Prevent out-of-phase reclosing between HONI‘s distribution system and

the DG facility

Reduce the risks of safety hazards caused by islanding

Add redundancy to other protections

At the present time, HONI will not allow islanded operation. Upon loss of voltage

in one or more phases of HONI‘s distribution system, the DG facility shall

automatically disconnect from all of HONI‘s ungrounded conductors prior to

reclosure. Reclosure times will be provided to the DG owner and are usually

between 1.0s and 2.0s.

Anti-islanding protection may involve different protection functions. Each DG

interconnected to HONI‘s system, shall contain this protection and must

demonstrate that the DG facility will not sustain an island longer than permitted. In

certain installations, the installation of dedicated communications (transfer trip) and

protection schemes may be required for anti-islanding protection and is discussed

in Section 3.2.16. Appendix D has detailed information on Anti-Islanding

Protection and discusses the different requirements for Transfer Trip. Please refer

to this appendix for more information. Induction generators, due to the possibility

of self-excitation, also have this requirement.

The DG facility, instead of using transfer trip for anti-islanding protection may use

an approved Hydro One Networks Anti-Islanding Protection Scheme. At present,

there are tests being conducted and if and when any of these schemes is

approved by HONI to meet anti-islanding protection requirements, they will be

posted in this section in a future revision.

To facilitate DG interconnections of 500kW and less, passive Anti-Islanding

protections, specifically Rate of Change of Frequency and Vector Jump or Reverse

Reactive Power, may be considered as an interim solution until an approved low-

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cost failsafe solution is finalized (ENERPULSAR pilot projects currently underway

– pulse based anti-islanding protection) These special considerations for DGs less

than 500kW have been made to enable these generators to connect with the

associated risks of passive anti-islanding technologies without having to wait for an

approved standardized solution.

It is in the DG Owners interest to make certain that the anti-islanding protection is

operational and will operate under all conditions with no non detection zone (NDZ)

as the DG Owner will be responsible for the damage to the DG facility that can

occur during out-of-phase reclosing.

3.2.16 Requirement for Transfer Trip

A Transfer Trip (TT) signal from the upstream feeder breaker/recloser to the DG

facility is required for any or all of the following conditions:

When the aggregate DG facility capacity is more than 50% of the

minimum feeder load, or

When the aggregate generation capacity on the feeder is more than 50%

of the minimum feeder load, or

When the aggregate DG facility capacity is 1 MVA or larger

If the existing reclosing interval time delay setting is short (dead time),

typically less than 1.0s

If any of the above requirements are met, then the DG facility shall cease to

energize HONI‘s distribution system after receiving a transfer trip signal. The DG

Facility is also responsible to make certain that upon transfer trip communication

loss, the DG facility will trip within 500ms for ―wired communications3‖ and within 5

seconds for wireless communications. The interrupting device used to disconnect

generation from HONI‘s distribution system must have maximum opening time of

85ms (time to open after receiving Transfer Trip signal from HONI).

3 Communications medium is wired, such as leased circuits, fibre, etc.

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3.2.16.1 Possible Exemption for DGs Smaller than 500kW

To facilitate DG interconnections of 500kW and less, passive Anti-

Islanding protections, specifically Rate of Change of Frequency and

Vector Jump or Reverse Reactive Power, may be considered as an

interim solution until an approved low-cost failsafe solution is finalized

(ENERPULSAR pilot projects currently underway – pulse based anti-

islanding protection) These special considerations for DGs less than

500kW have been made to enable these generators to connect with the

associated risks of passive anti-islanding technologies without having to

wait for an approved standardized solution.

3.2.17 DGEO (Distributed Generator End Open)

Hydro One Networks requires a Distributed Generator End Open (DGEO) signal

from the DG facility whenever transfer trip is required (see Section 3.2.16) to

confirm that the generator end has opened. Hydro One uses the DGEO signal for

the auto-reclose supervision of the TS feeder breaker or any upstream protective

device. This is to ensure that the DG facility HVI/LVI has opened and there is no

risk of out-of-phase reclosing. A combination of HVI and/or LVI status may be

used to key the DGEO signal. At the DG end, the DG is required to provide the

feeder protection with one signal that takes into account the Low Set Block Signal

(Refer to Section 3.2.22 ―LSBS (Low Set Block Signal)) and the DGEO signal.

This dual function signal will be set to ‗1‘ when the breaker is open and set to ‗0‘ 1s

prior to the energization of the DGITs to allow temporary blocking of the upstream

protections to avoid mis-operations due to large inrush currents. Timings for

these signals and ―Design Considerations‖ can be found in Appendix E.

3.2.18 Unintentional Energization

The DG facility shall not be capable to energize HONI‘s distribution system when

the distribution system is de-energized.

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3.2.19 Connection to Hydro One Network’s System

The DG facility connection is restricted only to the ―normal‖ supply configuration.

The normal feeder supply configuration is considered to be when the feeder is

supplied from one TS feeder breaker (the normal supply breaker) and all normally

open line switches are open, as defined by Hydro One operating diagrams.

The CIA will clearly identify the ―normal‖ feeder supply configuration that was

studied and was determined to be acceptable for connection.

Alternate (abnormal) supply configurations may be required from time-to-time to

circumvent contingency situations (equipment failures, maintenance, upgrading

and repairs). Under such circumstances the DG facility must be disconnected.

Alternate feeder supply configurations are considered to be in effect when the

feeder section to which the DG is connected is supplied from other than the

―normal‖ Hydro One TS feeder supply breaker or if any of the normally open

feeder-end switches are closed extending the feeder, as shown on the operating

diagrams. Although other supply configurations may be of concern, the expected

most common alternate feeder supply configurations that will not facilitate DG

connection are as follows:

Back-up supply of load customers from the adjacent TS feeder breaker

(TS feeder tie switch closed)

Back-up supply of load customers from another TS

Extending supply to load customers connected to an isolated section of

an adjacent feeder normally supplied from another source by closing a

normally-open feeder-end switch

Different conditions need to be met before reconnecting to HONI‘s system,

depending if the outage is a momentary outage or sustained outage or shutdown.

They are explained below. Automatic Reconnection of the DG facility to HONI‘s

system is subject to specific requirements which can be found in Section 3.2.21

and Section 3.2.23.

3.2.20 Disconnection of DG facilities

The following steps need to be taken to disconnect the DG facility from HONI‘s

distribution system during abnormal conditions or upon the receipt of a TT signal.

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3.2.20.1 Disconnecting DG Generation

For the first occurrence of a fault on any portion of the faulted feeder,

Hydro One high-speed sensitive ―low set‖ protection should operate to

isolate the Hydro One supply from the fault. The DG generation must

also be disconnected without delay to disconnect the DG supply from the

fault, to ensure fault extinction, to avoid any sustained DG island

condition and to avoid interference with normal Hydro One supply

restoration using automatic reclosure.

Disconnection of DG generation will be accomplished by TT and/or DG

interface protection as outlined in Section 3.2. The DG generation will be

disconnected using the same LV devices that were used to synchronize

the generation to the Distribution System (or by opening the HVI if the

LV devices fail to disconnect). Wherever HV ground sources are

present, additional steps listed in Section 3.2.20.2 are required.

3.2.20.2 Disconnecting DG HV Ground Sources

As per Section 3.1.11 above, any DG connections that have a HV

ground source and a HVI must ensure that the ground sources will be

disconnected whenever TT is received or DG Interface protection

operates, as outlined in Section 3.2 above, by opening the HVI.

3.2.21 Reconnection of DG Facility

The DG facility cannot operate connected to any part of the Distribution System in

island mode. The DG cannot reconnect until the Distribution System feeder has

been successfully energized from the normal Hydro One source.

3.2.21.1 Reconnection of Hydro One Source (for a transient fault4)

This is not a requirement, however it outlines what must take place

before the DG can reconnect. Refer to Appendix F for a detailed

sequence of events and timing diagram.

Following the first protection operation, the Hydro One feeder breaker or

recloser will be automatically reclosed to quickly restore supply to load

4 Generally associated with a momentary outage - loss of supply is less than 15 minute

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customers. Typical reclosing times are 0.5 to 1 second for feeder

breakers and 1.5 to 2 seconds for reclosers.

The Hydro One low-set instantaneous (fuse-saving) protections are

always blocked when the feeder is re-energized. Blocking the low-set

protections prevents an immediate re-trip caused by high energization

current associated with transformer inrush and cold-load effects. Only

the Hydro One high-set and time-coordinated protections are available at

the time of Hydro One reconnection. The high-set and timed protections

are coordinated with feeder reclosers and fuses to provide selective

isolation of faults on the feeder. Should a fault be established at the time

of feeder energization, these protections will operate as required to

isolate only those sections of the feeder required to clear the fault,

allowing service to be restored to the un-faulted sections.

Approximately 10 seconds after a successful automatic reclose

operation, all Hydro One feeder protections should be restored to their

normal state (complete with the low-set protections enabled).

3.2.21.2 DG Facility Reconnection

Reconnection to Hydro One Networks distribution system is a two step

process as outlined below for DG Facilities equipped with a required

HVI5 DG facilities not requiring a HVI only need to follow Step 2. Step

1 and Step 2 can occur simultaneously if the DG has facilities for

synchronizing the generation via the HVI.

Step 1: DGIT Re-Energization

For DG Facilities not requiring a HVI, this step can be ignored.

Where a DG HVI was used to disconnect the DGIT, and the HVI is not

used for synchronizing generation, the first step in reconnecting the DG

is to close the HVI. However the DGIT must not be re-connected until

after the feeder has been successfully re-energized from Hydro One

source and the Hydro One feeder protections have been restored to

their normal state (10 seconds there-after). To ensure this, the DG HVI

can be allowed to automatically reclose only after voltage and frequency

5 Provision of an HVI is dependent on DG Interface Transformer winding configuration – Refer to Section

3.1.11.

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are restored within normal limits for a period of 15 seconds (refer to

Section 2 for details on operating characteristics of HONI‘s Distribution

system). Note: feeder reclosers may have multiple reclose attempts to

allow sectionalizers to operate to clear the fault. The 15 second

restoration period begins after the final successful reclose. Therefore,

restoration time delay should reset every time the feeder is de-

energized.

For DGIT with large transformer in-rush current, the sensitive Hydro One

low-set instantaneous protection may need to be temporarily blocked to

prevent re-tripping of the feeder when re-energizing the DGIT. In those

cases, just prior to re-energizing the DGIT, the DG facility will need to

alter the DGEO signal momentarily to provide a signal to the Hydro One

location that the low-set protection needs to be blocked. (Refer to

Section 3.2.22 for LSBS requirement).

There may also be a need to stagger the re-energization of multiple

DGITs, to minimize the effects of inrush on HONI‘s distribution system

and the resulting voltage sag and flicker. The HVI closing delay can be

set between 15 seconds and 30 seconds – HONI to coordinate the

staggered timing. The generators shall stay disconnected during this

time.

Step 2: Generator Reconnection

Following a disturbance to HONI‘s distribution system, no reconnection

may take place until HONI‘s system voltage is within 6% of nominal and

the frequency is between 59.5Hz and 60.5Hz.

The generation facility‘s interconnection system must include an

adjustable delay that may delay the reconnection for 5 minutes after

Hydro One‘s steady state voltage and frequency are restored to the

normal operating ranges identified above, following a momentary

outage. The reconnection of multiple DG units on a feeder may require

being staggered.

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Reconnecting generation is most typically done using LV synchronizing

facilities. If synchronization occurs via the HVI, Step 1 and Step 2 occur

simultaneously.

For DG facilities not equipped with a HVI, there may be a requirement to

send out a Low Set Block Signal prior to closing of the disconnect switch

to energize the DGIT. Refer to Section 3.2.22 for LSBS requirements.

Automatic reconnection is not allowed for outages longer than 15

minutes. HONI‘s operators must give permission before reconnection

occurs.

Additional requirements listed in Section 3.2.23 ―Auto-

Resynchronization/Reconnection‖ need to be met for this automatic

reconnection following a momentary outage to occur.

3.2.21.3 Lock-Out of Hydro One Source (For a Permanent Fault)

This section outlines what occurs on HONI‘s distribution system during a

permanent fault condition. Refer to Appendix F for a detailed sequence

of events and timing diagram.

If a fault re-occurs after a reclose attempt, the affected section of HONI‘s

distribution system shall be tripped again. Automatic reclosure will then

be inhibited and Hydro One supply will have to be manually restored.

Some protective devices have as many as four reclose attempts before

reclosing is locked out.

Manual restoration of the feeder will be attempted by the Hydro One

controlling authority. That may occur within a few minutes where remote

control is available. If a remote-controlled manual restoration attempt is

successful, and within 15 minutes of the loss of supply, then DG

reconnection can proceed as per Section 3.2.21.2 above. Otherwise a

sustained outage or shut-down will be necessary (greater than 15

minutes).

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3.2.21.4 Restoration Following a Sustained Outage or Shutdown

No automatic reconnection of the DG facility may occur following a

sustained outage or shutdown – when the voltage and/or frequency out

of normal operating range on any phase for more than 15 minutes.

Permission to reconnect must be given by HONI‘s operators.

3.2.22 LSBS (Low Set Block Signal)

To ensure that the energization of the DG Interconnection Transformer following a

sustained outage or shutdown does not cause the Low Set Instantaneous

protections at HONI‘s feeder breaker to operate, a Low Set Block Signal (LSBS)

needs to be sent to HONI‘s feeder protections.

At the DG end, the DG is required to provide the feeder protection with one signal

that takes into account the Low Set Block Signal (Refer to Section 3.2.22 ―LSBS

(Low Set Block Signal)) and the DGEO signal. This dual function signal will be set

to ‗1‘ when the breaker is open and set to ‗0‘ 1s prior to the mechanical closing of

the HVI, or motorized disconnect switch, such that the feeder protection can

recognize the change of status and block the low-set instantaneous prior to the

energization of the DG Interface Transformer. Timings for these signals and

―Design Considerations‖ can be found in Appendix E.

This is a requirement wherever Transfer Trip and DGEO are required.

3.2.23 Auto-Resynchronization/Reconnection

Following a disturbance on HONI‘s distribution system, no reconnection may take

place until HONI‘s distribution system voltage and frequency are in the ranges

allowed in Section 3.1.5 and 3.1.7 respectively.

Auto-resynchronization/reconnection may occur if agreed by HONI for momentary

outages (distribution system voltage and frequency out of range for less than 15

minutes). The DG facilities interconnection system must include an adjustable

delay (from 5 minutes to 60 minutes after HONI‘s distribution system stabilizes)

that may delay the reconnection to HONI‘s system. HONI may coordinate the

restart time settings of DGs on the feeder in order to stagger the restarts and

minimize the effects of inrush to HONI‘s customers from the DG facilities upon

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energization. Refer to Section 3.2.21 for more information on the steps required to

automatically reconnect to HONI‘s distribution system. Appendix F contains

detailed sequence of events and timing diagrams for informational and design

consideration purposes.

HONI requires to have the ability to prevent auto-resynchronization/reconnection if

operating deems necessary. Auto-resynchronization/reconnection shall be locked

out once voltage and frequency are not within operating ranges for a period of 15

minutes on any phase.

No automatic reconnection to HONI‘s distribution system will be allowed unless:

There is always customer contact with the ability to immediately

disconnect from the system if requested by HONI (24 hours/7 days per

week, or

HONI has the ability to remotely disconnect and lockout the DG customer

from the system, and

Feeder relay studies must be updated if circuit configuration is materially

altered. If the source changes from the configuration studied in the CIA,

the generator will not be allowed to reconnect.

3.2.24 Synchronization Protection

Any DG facility that is capable of generating its own voltage while disconnected

from HONI‘s distribution system shall require proper synchronization facilities

before connection is permitted. Interconnection shall be prevented if the DG and

HONI‘s distribution system is operating outside the limits specified in Section

3.1.19.

3.2.25 Telemetry and Targeting

The DG facilities protection schemes shall have systems in place to record and

provide upon request to HONI an electronic record of protective device operations,

or failures to operate. Refer to Section 3.3.4 for additional requirements.

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3.2.26 Transformer Protection


Zero sequence currents circulating in the delta of a Wye-Delta transformer

during certain load and fault conditions are inevitable and if sustained, may

cause damage to the transformer. The design of the DG facility may require

transformer protection to prevent damage due to this phenomenon.

3.2.27 Protection from Electromagnetic Interference (EMI)

The DG interconnection system must have the capability to withstand

electromagnetic interference (EMI) environments in accordance with ANSI/IEEE

Std. C37.90.2, ―IEEE Standard for Withstand Capability of Relay Systems to

Radiated Electromagnetic Interference from Transceivers.‖ The influence of EMI

must not result in a change in state or misoperation of the DG facility – EMI must

not result in failure, misoperation or provide inaccurate information from the

protection, control and communication functions of the interconnection system.

The DG Owner shall provide documentation of compliance.

3.2.28 Surge Withstand Performance

The interconnection system must have the capability to withstand voltage and

current surges in accordance with the environments defined in IEEE/ANSI Std.

C62.41.2, ―IEEE Recommended Practice on Characterization of Surges in Low-

Voltage (1000 V and Less) AC Power Circuits‖ or IEEE Std. C37.90.1, ―IEEE

Standard for Surge Withstand Capability (SWC) Tests for Relays and Relay

Systems Associated with Electric Power Apparatus – Description.‖

The protection, control and communication equipment of the interconnection

system shall not fail, misoperate, or provide misinformation due to voltage or

current surges. CSA Std. C22.3 No.9-08, ―Interconnection of Distributed

Resources and Electricity Supply Systems,‖ provides more detailed information.

3.2.29 Special Interconnection Protection

Other protection not specified in this requirements document may be required

depending on the application. The DG Owner needs to be aware of site specific

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conditions and the nature of HONI‘s distribution system to properly assess the

need for additional protections.

3.2.30 Batteries/DC Supply

The DG facility requires a reliable power supply for its protections to function.

Batteries shall be provided and shall have adequate capacity to ensure that all

protection functions operate when the main source of power fails. They shall

remain operational for the time required for protection functions to operate properly

and disconnect the DG facility from HONI‘s distribution system. This source can

be achieved by using batteries and chargers connected to the main service supply

or by using an uninterruptable power supply with sufficient capacity for the

application. The battery voltage shall be monitored and upon failure, the protection

scheme shall be considered failed and DG facility shall be disconnected from

HONI‘s distribution system.

The following design criteria shall be considered:

The relays connected to the DC supply must not be subjected to

sustained overvoltages – if there is a possibility that the DC rating of the

equipment will be exceeded, steps shall be taken to ensure that DC

voltage limiting devices be installed at each relay

Dual station batteries will not be required for protection and control

equipment.

Protection systems designed to back each other up, will be supplied by

physically separated and protected DC supplies.

Circuit breakers and HVI‘s shall be powered by separate and dedicated

DC supplies.

Separate and independent means are to be used for tripping the HVI

and motorized disconnect.

Upon low voltage condition, the protections shall trip the generators and

open the HVI.

Capacitors shall not be used as the primary means to store energy in lieu of

batteries.

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3.2.31 Protection Scheme Failure

The DG facility must promptly disconnect (without delay) from HONI‘s distribution

system and notify HONI‘s system operators if the interconnection protection

system fails, breaker trip coil fails or if DC supply is lost. The breaker(s) must

remain open until such a time when the affected system is returned to normal

service condition and the DG facility is safe for reconnection to HONI‘s system.

The DG Owner shall provide evidence to HONI that the design of the DG facility is

sufficient to mitigate the risks associated with protection scheme failure by using

self-diagnostic features (available with IEDs), redundancy or a fail-safe design.

The availability (health) of the TT and DGEO signals, the DG self-clearing

protection, the DG breaker and the associated power supplies must be

continuously monitored by the DG and all DG sources of energy to the distribution

system must be immediately disconnected or disabled if any facilities fail or

become disabled. The design of the protections at the DG facility shall be done by

a qualified professional engineer to ensure that the overall protection scheme will

ensure a safe and reliable interconnection to HONI‘s distribution system.

Malfunctioning, self-diagnosing relays, shall notify operating personnel, and if no

redundancies are in place, shall disconnect the DG facility from HONI‘s distribution

system until the malfunction has been repaired.

In designs where self diagnostic features do not trip the appropriate breakers upon

failure, sufficient backup and/or redundancy protections shall be provided. If

electro-mechanical relays are used, the protection and control design shall be of a

fail-safe nature to ensure the integrity of the protection scheme under

malfunctioning conditions.

3.2.32 Teleprotection Scheme Failure

3.2.32.1 Transfer Trip Channel Failure

In the event of the transfer trip communication channel failing, the DG

facility shall disconnect from HONI‘s system within 500ms for wired

communications, such as fibre and leased circuits, and within 5s for

wireless communications. The DG facility protection design shall ensure

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that the teleprotection system is failsafe and that upon loss of transfer

trip, it will automatically trip the facility. The DG facility shall remain

disconnected until the transfer trip channel is repaired.

3.2.32.2 DGEO Channel Failure

In the event that the DGEO (refer to Section 3.2.17) communication

channel fails, HONI will block its feeder reclosing until the channel is

repaired. To maintain the reliability of the system for HONI‘s customers,

HONI reserves the right to send transfer trip to the DG and trip the DG in

order to allow automatic reclosing on its feeders. The DG Owner shall

ensure that repairs are conducted as quickly as possible.

3.2.33 Generators Paralleling for 6 Cycles or Less (Closed Transition Switching)

DG facilities paralleling for 6 cycles or less shall have the following protections:

Under-voltage protection to ensure that the generator is not capable of

energizing HONI system if it is de-energized

A 6 cycle timer to ensure that the DG will not parallel with HONI‘s

distribution system for more than 6 cycles.

Synchronization facilities, where required, must follow the requirements

specified in Section 3.1.19

The generator will be exempt from all other requirements of this document.

3.2.34 Instrument Transformers for use in Protection Systems

All instrument transformers used in DG facilities for protections shall meet the

requirements of IEEE C57.13 or CSA-C60044-6.

3.2.35 Provision for Future Changes

The DG Owner shall be responsible to stay aware of future changes to the

business environment and technical requirements and make any necessary

changes to its facilities. If HONI advises the DG Owner of required changes, the

DG Owner will make changes to the DG facility. The DG Owner is responsible for

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making any changes to the DG facilities in response to meeting new or revised

standards or due to HONI distribution system changes. Therefore it should make

any provisions to accommodate changes efficiently. The DG Owner may be

responsible for the costs associated with these changes, including changes that

originated at HONI‘s request.

3.2.36 Interconnection Protection Acceptance

The DG Owner must provide Hydro One Networks Inc. with complete

documentation on the proposed interconnection protection scheme with:

a detailed Single Line Diagram

overall description on how the protection will function including during

failure modes

details on protection components such as manufacturer and model #

the protection component settings (pickup, timers, etc.)

details on monitoring for the protection system and recording protection

operations/misoperations

details on the disconnecting and interrupting device

This information will be reviewed by HONI against the requirements of this

document and all applicable standards for the potential impacts to HONI‘s

distribution system. If HONI proposes any changes, the DG Owner must revise

and re-submit the protection information to HONI.

All documentation must be submitted together. The latest submissions will be filed

by HONI and MUST MATCH the documentation retained by the DG Owner.

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3.2.37 Protection Summary

This document discusses the common protection required for DG interconnection

to HONI‘s distribution system. The minimum required interconnection protections

are:

Over-Voltage

Under-Voltage

Over-frequency

Under-frequency

Overcurrent/Distance protection

Anti-Islanding Protection

Other protections may be required depending on the application. All protection

designs must ensure proper coordination with HONI‘s protections, be failsafe and

ensure that both the DG and HONI‘s distribution system, customers and general

public safety are maintained.

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3.3 Control and Telecommunications Requirements

3.3.1 General

Control and telecommunications facilities will be required at customer facilities

connected to the Hydro One transmission and distribution system for provision of

protection and real time operating data. The Customer shall provide battery

backup for telemetry in the event that the facility is removed from the HONI

transmission or distribution system. Battery backup capacity shall be sufficient for

the connection to be re-established. Alternatives to battery backup are subject to

approval by HONI.

Under the TSC6, DSC and terms of this document, owners of generating stations

connected to HONI‘s transmission and distribution facilities have an obligation to

provide real time data pertaining to their equipment as required by the capacity at

the PCC. Monitoring and control may be required as a result of Renewable Energy

Supply Integration initiatives regardless of the capacity as will be determined by

HONI. Installation capacity descriptions shall be consistent with the class

definitions of IEEE 1547.3 which has been included here in Table 9 for

convenience.

Table 9: DG Classification

Class Generation Capacity at PCC

1 0 kW < DG rating < 250 kW 2 250 kW ≤ DG rating < 1500 kW 3 1.5 MW ≤ DG rating ≤ 10 MW 4 10 MW < DG rating

These requirements for real time operating information apply to all customer-

owned generating stations connected to HONI‘s transmission or distribution

network. The quantities and device statuses, defined below, shall be provisioned,

monitored and controlled for continuous transmission to HONI. Such details are to

be captured in Schedule I of the Customer‘s TCA, or an appendix in the DCA as

required by HONI and the applicable codes.

6 TSC Appendix 1, Schedule E, Section 1.6

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3.3.2 Control Facilities

Subject to the agreement between the customer and Hydro One, all or some of the

following remote controls shall be provided to Hydro One:

(i) Station breakers and switchers

(ii) Motorized disconnect switches

(iii) Transformers‘ ULTC

(iv) 3% and 5% voltage reduction

(v) Hold off on feeder breakers

(vi) Dynamic generator output control

(vii) Other location specific devices

At any time, one and only one operating authority shall have remote control of the

station.

Where the customer maintains an operating centre and control of the station is

handed off from the customer to Hydro One at scheduled times, Hydro One will

consider the use of an ICCP link between the two control centres.

3.3.3 Telecommunication Facilities

Customers can provide real time operating information to HONI directly from the

station(s) or from the customer‘s SCADA master, as described below.

The customer shall provide the GPS coordinates of the facility to assist in the

evaluation of wireless communication alternatives.

The customer will provide all the required hardware and software and make

arrangements, as needed, with a commercial provider of communication services

to deliver the operating data to the demarcation point. Each DG Owner will be

responsible for all costs, initial and ongoing, and maintenance of their equipment

and communication circuits up to the demarcation point.

(a) From the IED at the customer‘s station to HONI‘s control centre using

serial DNP 3.0 protocol as follows:

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(i) to HONI‘s wireless cellular data hub site and through the gateway to

HONI‘s control centre, with the demarcation point being inside

HONI‘s hub site.

(ii) where (i) is not feasible, to HONI‘s communication hub site and

through the gateway to HONI‘s control centre, with the demarcation

point being inside HONI‘s hub site

(iii) where (i) and (ii) are not feasible, to a HONI HV station and through

the RTU or gateway to HONI‘s control centre, with the demarcation

point being inside HONI‘s station

(iv) where (i) through (iii) are not feasible, through a Frame Relay

Network of a common carrier to HONI‘s control centre, with the

demarcation point being the CO nearest to the customer‘s station

(v) where (i) through (iv) are not feasible, HONI will suggest

communication circuit options available for a particular site.

Where modems will be used in any of the above communication methods,

HONI will determine the modem type and requirements considering

communication media, site location, reliability, and amount of data transfer.

(b) From a SCADA master through a Frame Relay Network to HONI‘s SCADA

master using ICCP. The communication demarcation point will be the CO

of a common carrier.

3.3.3.1 Reliability Requirements

The delivery of the real time data at the communication demarcation point

shall have unplanned failure rates and repair times as described in the

table below:

Table 10: Unplanned Telecommunication Failure Rates and Repair Times

Failure Mean Time to Failure

Mean Time to Repair

Failure to deliver data from a single station

4 years 24 hours

Simultaneous failure to deliver data from 2 to 5 stations

5 years 4 hours

Simultaneous failure to deliver data from more than 5

stations 20 years 4 hours

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Prior to connection to HONI facilities, the customer shall submit a reliability

evaluation report which demonstrates that the above reliability

requirements can be satisfied.

The customer must coordinate any planned interruption to the delivery of

real time data with Hydro One.

3.3.4 Operating Data, Telemetry and Monitoring

In addition to the requirements in the sections of the TSC listed below, the

following additional requirements apply:

Real-time data to be provided to HONI by the customer:

3.3.4.1 Class 1 Generators

Generating facilities with a capacity of less than 250KW shall have

provision for monitoring the disconnecting device at the PCC.

Provisions for other quantities may be required and shall be determined by

HONI.


Generating facilities with a capacity of greater than or equal to 250KW but

less than 1500KW shall provide the following information:

A) Analogue Quantities

(a) Net active power (MW) output and reactive power (MVAR)

flow and direction for each unit or total for the facility

(b) Phase to phase or phase to neutral voltages

(c) Three phase currents

B) Device Statuses

(a) All LV breakers/circuit switchers at the PCC

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(b) AVRs and PSSs that impact the distribution system

(c) All generation rejection selections

C) Alarms

Provision shall be made for an alarm signal to be generated and

transmitted to HONI for transfer trip/DG end open (DGEO), loss

of communication (protection schemes) and loss of customer

owned interface protection (failed and disabled). A separate

alarm must be provided for each circuit supplying the customer.

The alarms shall identify the name of the customer facility and

the designation of the affected circuit. HONI shall determine

requirements based on controlling authority and equipment

ownership.

Monitoring and control may be required as a result of Renewable Energy

Supply Integration initiatives regardless of the capacity as will be

determined by HONI


Generating facilities with a capacity of greater than or equal to 1500KW but

less than 10MW shall provide the following information:

A) Analogue Quantities

(a) Net active power (MW) output and reactive power (MVAR)

flow and direction for each unit or total for the facility

(b) Phase to phase or phase to neutral voltages

(c) Three phase currents

B) Device Statuses

(a) All LV breakers/circuit switchers at the PCC

(b) AVRs and PSSs that impact the distribution system

(c) All generation rejection selections

C) Alarms

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Provision shall be made for an alarm signal to be generated and

transmitted to HONI for transfer trip/DG end open (DGEO), loss

of communication (protection schemes) and loss of customer

owned interface protection (failed and disabled). A separate

alarm must be provided for each circuit supplying the customer.

The alarms shall identify the name of the customer facility and

the designation of the affected circuit. HONI shall determine

requirements based on controlling authority and equipment

ownership.

Monitoring and control may be required as a result of Renewable Energy

Supply Integration initiatives regardless of the capacity as will be

determined by HONI


Generating facilities with a capacity of greater than 10MW shall provide the

same data as identified for Class 3 generators.

3.3.4.5 Telemetry Reporting Rates

Table 11 states the minimum requirements for telemetry reporting rates for

DGs (Class 1, Class 2, Class 3, and Class 4) interconnecting to HONI‘s


Table 11: Telemetry Reporting Rates

Function Performance

Data measurements less than 10 s from change in field monitored quantity

Equipment status change less than 10 s from field status change

Data skew not applicable

Scan period for data measurements

Minimum 4 s (1)

Scan period for equipment status

Minimum 4 s (1)

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3.3.5 Monitoring Reporting

HV Connected and Class 3 & 4 Facilities

Adverse situations involving the operation of the transmission or distribution

system, such as false trips or misoperations must be reported to the appropriate

Controlling Authority and regulatory authorities. It is expected that any protection

operation involving the customer facility will be fully documented along with

appropriate records from monitoring devices and provided to HONI immediately

following any such operation.

Any transmission or distribution connection facility owner must comply with

requests for sequence of events records (SER) or digital fault records as

requested by HONI or any controlling authority such as the IESO or NPCC within

30 days of request.

Waveforms and event data supplied to HONI must be in COMTRADE format.

Customer owned stations shall analyze all protection system misoperations in

order to take corrective actions to avoid future misoperations.

For further requirements, please refer to Section 8.

3.4 Performance Requirements

3.4.1 Power Quality

The DG facility must not negatively impact the power quality of Hydro One‘s

Distribution System. If the DG facility is found to cause problems and impact the

power quality of the system, they may be required to disconnect from HONI‘s

system until such a time when appropriate measures have been taken to mitigate

the adverse effects that the DG facility has been causing. IEEE Std. 519 should

be consulted to determine industry standards for power quality along with the

requirements in this document.

HONI requires Class 2, Class 3 and Class 4 DG installations (DG facilities greater

than 250 kVA) to be equipped with power quality meters that will monitor

continuously (and maintain logs) to ensure that power quality is maintained while

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the DG is on-line and off-line, and in steady and dynamic states. This power

quality device is to be capable of high speed sampling to capture parameters such

as voltage, current and harmonics and measures shall be taken to ensure the

device is time synchronized. The DG Owner is required to install and commission

this at its own expense and shall allow HONI access to such PQ data as required.

This will allow HONI and the DG owner to assess the condition of the power output

of the DG facility.

3.4.1.1 Voltage Fluctuations (Flicker)

The DG facility must not create objectionable flicker for other customers on

Hydro One‘s system. The voltage dip at the PCC should not be more than

4% on connecting the single largest generation unit in the facility and

should remain within 10% of nominal voltage when the entire facility trips.

The DG Owner shall take steps to make sure that flicker requirements are

met – may need to add loss of synchronism protection, stagger generator

energization, etc.

Indicative values of planning levels for Pst and Plt in HONI‘s distribution

system are shown in the table below. These limits are from IEC 61000-3-7,

and the standard should be consulted for more details. These values

should be measured by an approved flicker-meter that conforms to

CAN/SCA-C610004-15.

Table 12: Pst and Plt Flicker Limits

44kV 27.6/25/13.8/12/8/4 kV

Pst 0.8 0.9

Plt 0.6 0.7

3.4.1.2 Voltage and Current Harmonics

The DG facility shall not inject harmonic current that causes unacceptable

voltage distortion on HONI‘s distribution system. The DG facility shall

follow the requirements of IEEE Std. 1547 and CSA 22.2 No. 107.1 for

maximum harmonic current distortion, also shown below in Table 12, and

ensure that the facility is operating within these limits. The DG Owner

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and/or HONI may be required to implement measures that will mitigate the

harmonic distortions such as by adding harmonic filters, at the DG Owners

cost.

The CSA standard excludes harmonic currents that are due to harmonic

voltage distortions present on HONI‘s distribution system when the DG

facility is not connected. Inverters certified to this standard will be

considered to meet these requirements.

This document does not impose design limits to limit harmonic-caused

telephone interference problems as it is almost impossible to predict.

However, the DG Owner may want to make sure that the design complies

with all applicable standards and will not cause telephone interference.

Table 13: Current Harmonic Limits

Individual harmonic order, h

h < 11 11 ≤ h < 17 17 ≤ h < 23 23 ≤ h < 35 35 ≤ h THD

Distortion, percentage of current†‡

4.0 2.0 1.5 0.6 0.3 5.0

† The current is the greater of the distribution system maximum current integrated

demand (15 or 30 minutes) without the DG facility or the DG facility rated current capacity, transformed to the PCC when a transformer exists between the generators and the PCC.

‡ The maximum distortion presented in this table is for odd harmonics. Even harmonics are 25% of the odd harmonics presented above.

3.4.1.3 Voltage and Current Unbalance

The DG facility shall be capable of operating under existing conditions and

shall not cause deterioration of existing unbalance voltage and current

conditions.

3.4.1.4 Limitation of DC Injection

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The DC current injection by the DG facility shall not be greater than 0.5% of

the full rated output current at the PCC after a period of six cycles following

the energization of Hydro One‘s distribution system.

3.4.2 Disturbances

The DG facility shall be designed, built and maintained to all applicable codes,

regulations and standards, along with the requirements of this document and shall

minimize the impact of:

Overvoltages during ground faults

Electric disturbances which can cause irregular power flows

Interference – radio, television and telephone

Audible noise

Other disturbances which may reduce the reliability of HONI‘s

distribution system

3.4.3 Generator

3.4.3.1 Reactive Power Requirements

The generator‘s system shall operate in the preferred range of 0.9 lag to

0.95 lead. Hydro One Connection Impact Assessments will assess the

impact of the generator over the specified range of power factors.

For certain Distribution System loading conditions, Hydro One may require

the generator to restrict reactive power within a specified range or to

operate at a specific power factor level to maintain Distribution System

voltage levels within the required ±6%.

Field settable fixed and dynamic power factor correction techniques may be

used if consultation with Hydro One reveals no adverse affect on the


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For generators that are IESO impactive, the reactive power compensation

at the generating units should be sufficient so as not to cause any material

increase in the reactive power requirements at the transmission system

transformer station due to operation of the units, at any distribution feeder

load conditions.

3.4.3.2 Speed Governors

Speed governors control the dynamic machine speed at all times and

controls machine active power when the generator is connected to the


Speed governors are required to control generator speed for

synchronization purposes as outlined in Section 3.1.19.

Speed governors are required to maintain acceptable power quality as per

Section 2.6.

Speed governors / generator active power also impacts Distribution System

voltage profiles that are affected by both active and reactive power flows

along the Distribution System feeders.

Speed governors are expected to limit generator active power to the name

plate capacity as submitted to Hydro One for the Connection Impact

Assessment. Hydro One Connection Impact Assessments will assess the

impact of the generator over that range of active power. For certain

Distribution System loading conditions, speed governors may be required

to limit active power to specific levels as required by Hydro One to maintain

Distribution System voltage levels within the required ±6%.

Speed governors may also be required to limit active power to specific

levels to ensure self-clearing anti-islanding protections remain effective for

certain Distribution System loading conditions (generator power output

must not exceed 50% of potential minimum islanded load if Transfer Trip is

not available).

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Speed governor response also impact generator stability during power

system disturbances and their action needs to be considered in any system

stability studies that may be necessary for high impedance generator

connections.

Large generators (greater than 10 MVA) may have additional excitation

equipment requirements as specified by the IESO

At any time Hydro One may determine and require other specific speed

governor control or performance that is necessary to maintain acceptable

Distribution System conditions.

3.4.3.3 Excitation Equipment

Excitation equipment controls generator terminal voltage at all times and

controls generator reactive power when the generator is connected.

Excitation equipment is required to control generator terminal voltage and

PCC voltage for synchronization purposes as outlined in Section 3.1.19.

Excitation equipment is also required to maintain acceptable power quality

as per Section 2.6.

Excitation equipment / generator reactive power also impacts Distribution

System voltage profiles that are affected by both active and reactive power

flows along the Distribution System feeders.

Generally, the DG facility should not actively regulate the voltage at the

PCC (as per IEEE Standard 1547-2003), when the generator is connected.

Otherwise uncoordinated voltage control (such as hunting) could result and

cause excessive tap-changer and regulator operations and/or unnecessary

fluctuations in Distribution System voltage. If necessary, Hydro One may

specify some limited voltage regulation to maintain Distribution System

voltage levels within the required ±6% and/or acceptable Power Quality.

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Excitation equipment is expected to limit generator reactive power to the

name plate capacity as submitted to Hydro One for the Connection Impact

Assessment.

Excitation equipment is required to maintain power factor within a specific

range or limits as specified in Section 3.4.3.1.

For certain Distribution System loading conditions, Hydro One may require

the generator to restrict reactive power within a specified range or to

operate at a specific power factor level to maintain Distribution System

voltage levels within the required ±6%.

Excitation equipment can impact generator stability during power system

disturbances. Their action needs to be considered in any system stability

studies that may be necessary for high impedance generator connections.

Specific excitation equipment features and adjustments may be required to

help maintain generator stability during power system disturbances to avoid

loss of synchronism, particularly for synchronous generators.

Large generators (greater than 10 MVA) may have additional excitation

equipment requirements as specified by the IESO

At any time Hydro One may determine and require other specific excitation

equipment control or performance that is necessary to maintain acceptable

Distribution System conditions.

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4 Metering Requirements

Metering shall be in accordance with Hydro One Networks NOP 041 document ―Policy –

Distribution – Metering for Embedded Generators.‖ A copy of this document can be found in

Appendix H near the end of this document.

5 Connection Process Requirements

The Connection Process is outlined in the Ontario Energy Board Distribution System Code

Appendix F1 (reference 1). For a complete description of that process consult the OEB

website http://www.oeb.gov.on.ca/OEB/.

The following describes the final steps of the connection process (after completion of the

initial steps: initial contact, provision of information, generator develops plan, initial

consultation, application for impact assessment, Impact Assessment, Decision to Proceed

and Establish Scope of Project, Prepare Estimate and Present Offer to Connect).

5.1 Implementation

Implementations must proceed in accordance with the Ontario Energy Board Distribution

System Code Appendix F1 (reference 1). This involves the following:

Both parties commit to project and Generator commits to obtain required approvals. The

Generator:

prepares detailed engineering drawings;

submits all detailed plans to ESA for Plan Approval process (including

detailed single line diagram, interface protection); and

submits information to Hydro One for design review (including detailed single

line diagram, interface protection and metering details)

is recommended to provide this information to Hydro One within 30 days of

signing CCA so that design review can be done in a timely manner.

http://www.oeb.gov.on.ca/OEB/

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Hydro One performs design review to ensure detailed engineering is acceptable. The

following is information is provided to the Generator:

the Interface protection design review;

Hydro One reviews detailed single line diagram and interface protection to

ensure acceptability; and

Recommend that this review be complete before equipment purchase.

Once Generator receives interface protection design review from Hydro One, then:

Generator tenders and awards contracts for equipment;

Builds - including ESA and other approvals;

Connection work; and

Line/equipment upgrades are completed.

Generator constructs facility and applies for ESA Electrical Inspection to receive

Authorization to Connect.

5.2 Connection Agreement

The Generator and Hydro One agree to, and sign, a Connection Agreement. Hydro One

and transmitter/host distribution system shall review existing agreements for required

revisions.

Note: A temporary connection agreement for the purpose of connection for

commissioning and verification may be signed at this point while negotiating final

Distribution Connection Agreement.

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6 Commissioning and Verification Requirements

Commissioning and Verification is required in accordance with the Ontario Energy Board

Distribution System Code Appendix F1 (reference 1). This involves the following:

Generator arranges for commissioning and testing of the generation facility;

Hydro One witnesses and verifies the commissioning process related to the

connection facilities; and

Transmitter/Host Hydro One witness and verify the commissioning process as

required

6.1 Hydro One Networks Inc. COVER Process

Hydro One requires the use of a ―Confirmation Of Verification Evidence Report‖

(COVER) to track the Generators Commissioning and Verification plans and execution.

The Customer Instructions for Completing the COVER form is contained on the form

itself (page 8). The complete 8-page COVER form is located in Appendix G. The

version of the COVER form may have changed since the time that this document has

been published.7 It has been provided for informational purposes only. The newest

version will be provided to the DG Owner at the appropriate stage of the project.

6.2 Hydro One Requirements for Commissioning and Verification

Hydro One's interest in the commissioning of the generator‘s equipment and systems is

limited to protection and control systems that impact operation of Hydro

One‘s distribution system. That involves the generator‘s protection and controls used for

the distribution system interface and synchronizing facilities for the distributed generation

connection. That includes end-end verification of all inputs and outputs (instrument

transformers, breaker positions, transfer trips, distributed generator end open schemes),

correct processing of those inputs by the protection and control systems for anti-

islanding and clearance of external faults, end-end verification of all outputs - breaker

tripping, breaker failure initiation, closing interlocks, alarms, and telemetry.

Hydro one requires commissioning of those protection and control systems to be

complete and thorough. Generator testing should conform to IEEE Standard 1547.1 -

7 The COVER form is subject to periodic review and revision. The current version will be provided by

Hydro One.

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Conformance Test Procedures for Equipment Interconnecting Distributed Resources

with Electric Power Systems. That standard specifies the type, production, and

commissioning tests that shall be performed to demonstrate that the interconnection

functions and equipment of the distributed resources (DR) conform to IEEE Std. 1547.

In general terms, the expected commissioning testing and supporting documentation

must include:

a) Instrument transformer checks (insulation, ratio/polarity, excitation and resistance

results).

b) Breaker timing trip tests for those breakers used to disconnect the distributed

generation from the Distribution System as a result of protection operations.

c) Verification of the transformer and neutral reactor impedances that impact the

generator ground integration with the Distribution System and correct connection,

where applicable.

d) Relay setting field work sheets (showing the measured results of the relay

calibration checks). Relay element settings/directioning are to be confirmed by AC

secondary injection.

e) Voltage measurements for any external power supplies used to supply the

protections should be recorded.

f) For AC and DC measurements, test equipment traceable to NRC standards should

be used.

g) Functional tests confirming the protection and control logic and timer settings.

h) Verification of test trips and alarm processing. Monitoring of breakers outputs

using suitable indicators can be used to avoid repeated tripping of the same from

different protections, but at least one live trip test per breaker (where the breaker

is proven to open) needs to be demonstrated.

i) Verification of control interlocks in protections

j) Verification of synchronizing system and synch-check controls.

k) Voltage phasing checks (prior to first connection).

l) Secondary load readings, voltage and current phasor checks (immediately after

first connection) to prove correct magnitude and phase angle of all secondary AC

voltage and current circuits correspond to primary quantities. Primary current,

voltage, MW and MVAr values must be calculated from the measured secondary

values and compared to known primary quantities at adjacent locations.

m) The completed documentations must clearly indicate the station, protection

designation, settings date, test date, the name of the tester(s), relay type

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(manufacturer and model), test equipment details (manufacturer, model, serial

number, accuracy, last calibration date), instrument transformer ratios. There

should be a cross-reference to the submitted design documentation (drawing

numbers and revision).

n) Verification of Transfer Trips and DGEO end-end checks. This will require

participation and coordination with Hydro One.

o) The Distributed Generator shall make modifications to correct any problems that

are found during commissioning.

p) As-constructed drawings (single line diagram showing protection and metering, AC

and DC schematics, final relay settings, testing and commissioning results for

interface protection etc.) shall be submitted to the Distributor for its records within

sixty (60) business days after the connection, as stipulated in the Connection

Agreement.

As per the COVER, Summary of testing results and certificates must be kept on file for a

minimum period of 7 years by the Customer (as indicated by IESO Market Rules, Chp.4,

5.1.3). Hydro One Networks Inc. may require this information, on an exception basis.

Complete documentation of all commissioning results will be required for the interface

protections and synchronizing controls, signed and stamped by a Professional Engineer

registered in the Province of Ontario. Those results must provide complete assurance

that the distributed generator equipment has been proven to function correctly, as per

the accepted design submissions and the Distribution Connection Agreement.

7 Maintenance Requirements

7.1 Protection and Control Systems Equipments

7.1.1 The Generator shall re-verify its station protections and control systems that impact

the Hydro One Distribution System. That would include the systems that were

confirmed and verified as part of the COVER process. Maintenance requirements

will be equivalent to what Hydro One would require for re-verification of its own

facilities that have similar potential impact to the Distribution System, normally every

eight (8) years.

7.1.2 Within three (3) months of Connection, the Generator shall provide Hydro One with

their proposed protection and control reverification program (including test

procedures and schedules).

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7.1.3 Within thirty (30) working days of receiving the above documentation or as required

by the Code, Hydro One shall notify the Generator that it:

(a) agrees with the proposed reverification program and test procedures; or

(b) requires changes in the interest of safety or maintaining the reliability of the

Distribution System. Such request for changes shall be sent to the Generator

Promptly.

7.1.4 For those tests that require Hydro One‘s participation or witnessing, the Generator

shall provide Hydro One with no less than fifteen (15) working days notice.

Note: All tests must be coordinated and approved ahead of time through the normal

outage and work management system planning processes.

7.1.5 The Generator will complete the re-verification in accordance with 7.1.3 above and

submit complete documentation of the test results to Hydro One within one month of

the completed tests.

8 Reporting Requirements for DGs

The Customer shall keep a written or electronic log. This log will record the date and time,

along with a description of the incident. The incidents recorded, must include, but are not

limited to those in the table below. The Generator must make the log, or a copy of the log,

available for the Distributor‘s review upon request, within five (5) working days of that

request.

The Customer will provide reports to the Distributor, Distribution Eng/Officer (See Schedule

F, Contact List - section 1) either on a requested basis, or for specific types on incidents that

require reports as per the table within five (5) working days of the incident.

The report must include, but is not limited to:

Distributed Generation Facility and/or Generator Name and Account Number

Supply Feeder

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Date and time of incident

General description of the incident, including cause, if known

Did the Generator's equipment trip correctly?

Voltage (if available)

Frequency (if available)

Amps

Active Power (kW or MW)

Reactive Power (kVAr or MVAr)

Any available oscillography or digital fault records (DFR) related to the above

Generator connection status (individual units)

Transfer Trip signal status

Distributed Generator End Open signal status

Which relays operated (targets & description)? Any available sequence of events

records (SER) related to the above

Corrective actions taken

These are the incident types to be recorded:

Note: the Distributor may modify the incidents to be logged or recorded in the table below,

based on those relevant to the Distribution System specific to this Connection.

Table 14: Incident Logging

Incident Logged Report Required Real Time

Communication

Protection System Malfunction or Failure at the Facility (see D.3.9.6)

Yes As requested Day of

Trip from the Facility‘s Relay Operation

Yes As requested Within Hour

Electrical failure / incident at the Facility

Yes As requested As requested

Mechanical failure / incident at the Facility

Yes As requested As requested

Trip from Feeder incident Yes As requested Within Hour

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9 References

1. Ontario Energy Board Distribution System Code Appendix F - Process and Technical

Requirements for Connecting Embedded Generation Facilities - Section F.2 Technical Requirements

2. Ontario Energy Board Distribution System Code

3. IEEE Std 1547-2003 - IEEE Standard for Interconnecting Distributed Resources with

Electric Power Systems

4. IEEE Std 1547.1-2005 - IEEE Standard Conformance Test Procedures for Equipment

Interconnecting Distributed Resources with Electric Power Systems

5. IEEE P1547.2/D11 Draft Application Guide for IEEE Standard 1547, Interconnecting Distributed

6. IEEE Std 1547.3-2007 - IEEE Guide for Monitoring, Information Exchange, and Control of

Distributed Resources Interconnected with Electric Power Systems

7. IEEE Std 519-1992 - IEEE recommended practices and requirements for harmonic control in electrical power systems

8. IEEE Std 929-1988 - IEEE recommended practice for utility interface of residential and

intermediate photovoltaic (PV) systems

9. IEEE Std C37.90-2005 - IEEE Standard for Relays and Relay Systems Associated with

Electric Power Apparatus

10. IEEE Std C37.90.1-2002 - IEEE Standard for Surge Withstand Capability (SWC) Tests for Relays and Relay Systems Associated with Electric Power Apparatus

11. IEEE Std C37.90.2-2004 - IEEE Standard for Withstand Capability of Relay Systems to

Radiated Electromagnetic Interference from Transceivers

12. IEEE Std C37.90.3-2001 - IEEE standard electrostatic discharge tests for protective relays

13. IEEE Std C57.13-2008 - IEEE Standard Requirements for Instrument Transformers

14. IEEE Std C57.13.1-2006 - IEEE Guide for Field Testing of Relaying Current Transformers

15. IEEE Std C57.13.2-2005 - IEEE Standard Conformance Test Procedures for Instrument Transformers

16. IEEE Std 929-1988 - IEEE recommended practice for utility interface of residential and

intermediate photovoltaic (PV) systems

17. IEEE Std 1159-1995 - IEEE Recommended Practice for Monitoring Electric Power Quality.

18. IEEE Std 242-2001 - IEEE Recommended Practice for Protection and Coordination of

Industrial and Commercial Power Systems - IEEE Buff Book

19. IEEE Std 1109-1990 - Guide for the Interconnection of User-Owned Substations of Electric Utilities

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20. IEEE Std 1001-1988 - IEEE Guide For Interfacing Dispersed Storage and Generation

Facilities with Electric Utility Systems

21. IEEE Std 1453-2004 - IEEE Recommended Practice for Measurement and Limits of

Voltage Flicker on AC Power Systems

22. IEEE Std 493-2007 - Gold Book - IEEE Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems

23. IEEE Std 1100-2005 - EMERALD BOOK - IEEE Recommended Practice for Powering and

Grounding Electronic Equipment

24. IEEE Std 1250-1995 - IEEE Guide for Service to Equipment Sensitive to Momentary

Voltage Disturbances

25. IEEE Std 100-1997 - IEEE Standard Dictionary of Electrical and Electronics Terms

26. IEEE Std 315-1975 - Graphic Symbols for Electrical and Electronics Diagrams

27. IEEE Std C37.2-2008 - IEEE Standard Electrical Power System Device Function

Numbers, Acronyms, and Contact Designations

28. IEEE Std C37.1-2007 - IEEE Standard for SCADA & Automation Systems

29. IEEE Std 80-2000 - Safety in AC Substation Grounding

30. IEEE Std 81-1983 - Guide for Measuring Earth Resistivity, Ground Impedance, and Earth

Surface Potentials of a Ground System Part 1: Normal Measurements

31. IEEE Std C62.23-1995 - IEEE Application Guide for Surge Protection of Electric Generating Plants

32. IEEE Std C37.29-1981 - IEEE Standard for Low-Voltage AC Power Circuit Protectors

Used in Enclosures

33. IEEE Std C57.12 - IEEE Standard General Requirements for Liquid Immersed Distribution,

Power and Regulating Transformers

34. IEEE Std C57.12.13 - Conformance Requirements for Liquid Filled Transformers Used in Unit Installations including Unit Substations

35. IEEE Std C57.13 - IEEE Standard Requirements for Instrument Transformers

36. IEEE Std C37.20.1-2002 - IEEE Standard for Metal-Enclosed Low-Voltage Power Circuit

Breaker Switchgear

37. IEEE Std C37.20.2-1999 - IEEE Standard for Metal-Clad Switchgear

38. IEEE Std C37.20.3-2001 - IEEE Standard for Metal-Enclosed Interrupter Switchgear

39. IEEE Std C37.30-1997 - IEEE Standard Requirements for High Voltage Switches

40. IEEE Std C62.41-1991 - IEEE Recommended Practice for Surge Voltages in Low-Voltage

AC Power Circuits

41. IEEE Std C37.010-1999 - IEEE Application Guide for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis

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42. CSA Std C22.1-2009 - Canadian Electrical Code, Part I Safety Standard for Electrical

Installations - Twenty-first edition

43. CSA Std C22.2 - Canadian Electric Code Part II

44. CSA Std C22.3 - Canadian Electric Code Part III (Electricity Distribution and Transmission

Systems).

45. CSA Std C22.3 No. 9-2008 - Interconnection of Distributed Resources and Electricity

Supply Systems

46. CSA Std C235-83-CAN3 - Preferred Voltage Levels for AC Systems, 0 to 50,000 V Electric Power Transmission and Distribution

47. CSA Std C22.2 No. 107.1-95 - Commercial and Industrial Power Supplies

48. CSA Std C22.2 No. 31-M89 (R2000) - Switchgear Assemblies

49. CSA Std C22.2 No. 193-83 (R2000) - High-Voltage Full-Load Interrupter Switches

50. CSA Std CAN3-C308-M85 - Principles and Practices of Insulation Coordination

51. UL 1741 - Inverters, Converters, and Controllers for Use in Independent Power Systems

52. IEC TR3 61000-3-7 - Principles and Practices of Insulation Coordination Assessment of Emission Limits for Fluctuating Loads in MV and HV Power Systems

53. IEC 61000-4-15 - Flickermeter—Functional and Design Specifications

54. IEC 61400-21 - Wind Turbine Generator Systems—Part 21: Measurement and Assessment

of Power Quality Characteristics of Grid Connected Wind Turbines—Ed. 1.0 (2001-12).

55. NEMA CC-1 – Electric Power Connectors for Substations

56. NEMA LA-1 – Surge Arresters

57. NEMA MG-1 – Motors

58. W. Xu, K. Mauch, and S. Martel. ―An Assessment of the Islanding Detection Methods and Distributed Generation Islanding Issues for Canada, A report for CANMET Energy Technology Centre‖ -Varennes, Nature Resources Canada, 65 pages.

59. Wilsun Xu, Guibin Zhang, Chun Li, Wencong Wang, Guangzhu Wang, Jacek Kliber, "A power line signaling based technique for anti-islanding protection of distributed generators: part I: scheme and analysis", IEEE Trans. Power Delivery, v22, n3, July 2007, pp. 1758 –

1766

60. Wencong Wang, Jacek Kliber, Guibin Zhang, Wilsun Xu, Blair Howell and Tony Palladino, ―A Power Line Signaling Based Scheme for Anti-islanding Protection of Distributed Generators: Part II: Field Test Results‖, IEEE Trans. Power Delivery , v22, n3, July 2007, pp. 1767 – 1772.

61. W. Freitas, Z. Huang, W. Xu, ―A practical method for assessing the effectiveness of vector surge relays for distributed generation applications‖, IEEE Trans. Power Delivery, v20, n1, pp. 57-63, Jan. 2005.

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A Appendix A - Device Number Description

The following is a list of relevant device numbers and their meaning:

21 - Distance Relay

25 - Synchronizing or Synchronism-Check Device

27 - Undervoltage Relay

31 - Separate Excitation Device

32 - Directional Power Relay

37 - Undercurrent or Underpower Relay

42 - Running Circuit Breaker

46 - Reverse-phase or Phase-Balance Relay

47 - Phase-Sequence Voltage Relay

49 - Machine or Transformer Thermal Relay

50 - Instantaneous Overcurrent

51 - AC Time Overcurrent Relay

52 - AC Circuit Breaker

53 - Exciter or DC Generator Relay

55 - Power Factor Relay

57 - Short-Circuiting or Grounding Device

59 - Overvoltage Relay

60 - Voltage or Current Balance Relay

61 - Machine Split Phase Current Balance

64 - Ground Detector Relay

67 - AC Directional Overcurrent Relay

68 - Blocking Relay

79 - AC-Reclosing Relay

81 - Frequency Relay

86 - Lockout Relay

87 - Differential Protective Relay

88 - Auxiliary Motor or Motor Generator

89 - Line Switch

90 - Regulating Device

91 - Voltage Directional Relay

92 - Voltage and Power Directional Relay

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B Appendix B – Neutral Reactor and Grounding Transformer Impedance Calculations for Inverter Based DG Facilities

The following is two examples for calculating the impedance of grounding transformers for

Inverter based DG facilities:

Example 1: for 10 MVA DG Facility connected at 27.6 kV,

Base impedance = 27.6kV2/10MVA = 76.2Ω,

Then X0 = 0.6 x 76.2Ω ± 10% = 45.7Ω ± 10%

Example 2: for 2 MVA generation connected at 27.6 kV,

Base impedance = 27.6kV2/2MVA = 381 Ω,

Then X0 = 0.6 x 381Ω ± 10% = 228.6Ω ± 10%

The following is two examples for calculating the impedance of neutral reactors for Inverter

based DG facilities:

Example 1: for 10 MVA DG Facility, with ten 1 MVA DGITs connected

at 27.6 kV,

Base impedance = 27.6kV2/1MVA = 762Ω,

Then X0 = 0.6 x 762Ω ± 10% = 457.2Ω ± 10%

Example 2: for 2 MVA generation connected at 27.6 kV,

Base impedance = 27.6kV2/2MVA = 381 Ω,

Then X0 = 0.6 x 381Ω ± 10% = 228.6Ω ± 10%

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C Appendix C – Timing Diagrams

The following are a few sample timing diagrams for informational purposes. These have been created to represent a

realistic sequence of events and the associated timings for different applications. These times may change due to site

specific requirements and thus, timing requirements shall be confirmed with HONI for specific DG projects.

Figure 17 and 18 represent timing for fault and island detection for DGs not equipped with Transfer Trip from HONI,

coordinating with HONI reclosers with a reclose time of 500ms and 1s respectively.

Figure 17: No Transfer Trip with 500ms Reclosure Upstream

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Figure 18: No Transfer Trip with 1s Reclosure Upstream

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Figure 19 and 20, shown below, show timing requirements DGs equipped with Transfer Trip from HONI, coordinating with

HONI reclosers with a reclose time of 500ms and 1s respectively.

Figure 19: Transfer Trip with 500ms Reclosure Upstream

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Figure 20: Transfer Trip with 1s Reclosure Upstream

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D Appendix D – Anti-Islanding Protection

The following is background information on Anti-Islanding Protection, its purpose, and some

rational behind some requirements. Transfer Trip and Distributed Generator End Open is

discussed. Also, a typical distribution system is shown and possible island formations are

discussed. This information is provided as informational only. Requirements are listed in

Section 3 of this document.

Transfer Trip, Distributed Generator End Open and Inrush Blocking (LSBS)

Transfer Trip (TT), Distributed Generator End Open (DGEO) and Inrush Blocking (Low Set

Block Signal – LSBS) are often required to mitigate the adverse impacts of DG connection and

islanding, as detailed below.

Transfer Trip (TT) is a protection trip signal that is sent from the Hydro One supply

source breaker or recloser to the DG when the DG is required to be disconnected.

Distributed Generator End Open (DGEO) is a real time signal that is continuously sent

from the DG to the Hydro One supply source breaker or recloser. It establishes the

connection status of the generation equipment. For 3-wire connections, the DGEO signal

is derived from all breakers/circuit switchers at the interface between the DG generation

and the PCC necessary to establish DG generation connectivity. For 4-wire

connections, the DGEO signal is derived from the DG HVI switch only. Refer to

Appendix E for more information regarding the DGEO signal.

Low Set Block Signal (LSBS) is a signal that is sent from the DG to the Hydro One

supply source breaker or recloser, whenever a large DG interface transformer (DGIT) is

being energized. Detection of this signal transition at the Hydro One supply source

breaker or recloser location will cause the most sensitive low-set (fuse-saving) protection

to be temporarily blocked. This will prevent tripping of the Hydro One supply source

during the period when there is large energizing inrush current due to the DGIT. Refer

to Appendix E for more information regarding the LSBS signal.

Because the momentary LSBS signal will always be sent just prior to reconnection, (near

the end of the DGEO open condition), it is possible to combine both DGEO and the

LSBS functions as one signal through a communication channel from the DG facility to

the Hydro One source energizing location(s).

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DG Islanding

DG islanding can expose Hydro One Transmission and Distribution Systems and customers to

unstable voltage and frequency and other adverse impacts. A DG island is formed if a DG

remains connected to a portion of the Distribution System after that portion is separated from

the normal Hydro One supply. Most typically, DG islanding can occur when the feeder breaker

or other isolating device at a TS or DS or along a radial-connected feeder is opened.

Some of the causes that may lead to DG islanding are as follows:

A fault that is detected and cleared by the utility before it can be detected and cleared by

the DG. Most DG islands will be established this way.

Emergency switching of distribution system and loads.

Equipment malfunction.

Operating or human error.

Foreign interference or other acts of nature.

Adverse Impacts of DG Islanding

Potential adverse impacts of DG islands include:

a) Abnormal voltage and frequency excursions outside of the acceptable ranges because

of DG voltage regulation limitations.

b) Excessive temporary overvoltage (TOV) can occur if DG sources that are not effectively

grounded back-feed single-line-ground faults.

c) Extreme overvoltage from ferroresonance between the nonlinear magnetizing

inductance of DGIT/induction generators and connected capacitance and system

capacitance.

d) Unpredictable DG energy sources that are not controlled by the utility. This includes

generation sources and abnormal phase voltages caused by back-feed through multi-

core 3-phase DG interface transformers in the presence of single-phase switching or

other open circuit supply conditions.

e) Failure to clear certain faults that cannot be detected by DG self-clearing protections

within required time.

f) Interference with the restoration of normal supply from the utility.

g) Asynchronous paralleling if DG is present when Hydro One supply is restored.

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The risks of these adverse impacts include:

a) Inadequate power quality - voltage and frequency.

b) Damage - to customer and utility line equipment as a result of overvoltages or sustained

or prolonged electrical faults where protections are insensitive or slow clearing.

c) Prolonged customer outages resulting from failed automatic reclosure or delays in

establishing safe conditions for isolation and repair of damaged equipment.

d) Safety hazards to public and utility workers since lines may be energized when it is

assumed to be disconnected from all energy sources.

e) Increased liability and costs associated with all of the above.

These impacts must be avoided by maintaining adequate controls over the design and

operation of the DG interconnections. Transfer Trip (TT) and Distributed Generator End Open

(DGEO) schemes are important tools that are required to avoid these adverse effects for certain

configurations.

Hydro One Supply Stabilizes Voltage and Frequency

Hydro One is responsible for supply and voltage regulation of Hydro One Distribution Systems

and maintains Distribution System voltages at acceptable levels as required by the OEB.

Frequency is maintained very close to 60 Hz by the synchronized interconnection of the Hydro

One Transmission System to the Eastern Interconnection of the North American Electric

Reliability Corporation (NERC).

Voltage and frequency will be maintained under normal system conditions as long as normal

Hydro One supply remains connected to the Distribution System.

Expected Frequency and Voltage Deviations in DG Islands

When a DG island occurs, island voltages and frequency will depend entirely on the interaction

between the islanded generation and load. Maintaining an island within acceptable limits would

require at least one DG in the island to actively regulate frequency and voltage to match

changing island load demands. Furthermore the DG capacity would have to be large enough to

sustain the extreme range of load demands that may exist in the island. DGs cannot meet

these conditions for the following reasons:

HONI does not permit DG voltage regulation systems to actively regulate voltage. This

avoids mal-coordination of Distribution System voltage regulation and excessive

operation of Hydro tap-changers and voltage regulators.

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Variable production conditions prevent DG capacity from being capable of meeting the

exact demands of any specific local loads or power transfers. As a result, DG island

frequency and voltage can be expected to drift outside of the acceptable limits because

of these inherent DG control and capacity limitations.

The direction (over or under) of frequency and voltage change for a DG island will

depend upon the relative mismatch of net real and reactive power between the islanded

DG and load. If the active power generation is less than the active power consumed by

the load, the island frequency will drop. If the active power generation exceeds the

active power consumed by the load, the island frequency will rise.

Change in island voltage magnitude depends similarly on mismatch between distributed

generation reactive power output and the reactive power demands of the islanded load.

The rate-of-change of frequency and voltage for a DG island will depend upon many

factors. These factors include the amount of power unbalance, network impedances,

voltage dependency of the feeder loads and dynamic characteristics of the islanded

generation and loads (inertias of the interconnected machines and transient reactances).

Even short duration DG islands may be too long to prevent adverse DG islanding

impacts, unless specific design precautions are implemented.

Possibility of Extreme Overvoltages and Back-feeds through Customer

Transformers

Ferroresonance and single-line-ground faults can cause extreme or excessive over-

voltages for some DG island configurations. These over-voltages are capable of causing

damage to customer and Hydro One equipment.

Back-feeds through multi-core 3-phase DG interface transformers in the presence of

single-phase switching or other open circuit supply conditions. These voltages pose a

safety hazard to public and utility workers for fallen conductors or when circuits are

assumed to be dead but in fact are energized.

These over-voltage and back-feed effects are largely dependent upon the size,

grounding and magnetic-core characteristics of the DG interface transformer (DGIT)

connections. There are many ways to avoid or minimize these effects. That includes

the following:

i. The use of Transfer Trip

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ii. Use of a DG HVI to be tripped whenever an unbalanced condition is detected

at the DG location

iii. Effective-grounding of DGIT

iv. Avoiding the use of multi-core transformers for 3-phase connections in the

presence of single phase switching upstream, by using three individual

single-phase (single-core) DGIT connections

v. Avoiding single-phase switching of 3-phase transformers (where possible) or

minimizing circuit capacitance from the DGIT to these locations.

Automatic Reclosure

Transient faults on over-head line conductors caused by lightning, wind, tree branches

falling, or other momentary foreign contact constitute approximately 85-90% of all faults.

Hydro One uses the standard utility practice of automatic reclosure on distribution

feeders with over-head line-sections to minimize supply interruptions for transient faults.

Automatic reclosure is not generally used for feeders with extensive underground cable

sections because cable faults are exposed to far fewer naturally occurring transient fault

conditions. Also faults on cables are much more likely to be permanent requiring repairs.

Benefits of Automatic Reclosure

Automatic reclosure has the following advantages:

Minimizes supply interruption to customers by automatically restoring the feeder to

service as quickly as possible following transient faults.

Minimizes damage at the fault and stress on equipment supplying the fault.

Reduces operating costs. Less time and materials required to repair damage and restore

service.

Prevents blowing of fuses at tapped Distribution stations and lateral feeds resulting in all

of the above.

How Automatic Reclosure Works

For the first occurrence of the fault on any portion of the faulted feeder, high-speed

sensitive ―low set‖ protection operates quickly to de-energize the feeder.

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Following the first protection operation, the Hydro One feeder breaker or reclosers are

automatically reclosed to restore supply to load customers as quickly as possible.

Typical reclosing times are 0.5 to 1 second for feeder breakers and 1.5 to 2 seconds for

reclosers.

Reclosing time must allow for the fault to extinguish and de-ionize.

Reclosing time must also allow some time for the inertia and back emf of large motors to

decay (to about 40% of normal voltage) and be disconnected by automatic controls.

Automatic Reclosure Requires DG to Disconnect Quickly

Automatic reclosure can succeed only if the fault arc is extinguished and de-ionized. Otherwise

the fault is likely to re-strike after the feeder is re-energized.

If the DG has not disconnected at the time that automatic reclosure takes place, the

reclosure would asynchronously re-parallel to all DGs and any rotating motors that

remained connected in the island.

Extreme mechanical stresses associated with asynchronous paralleling could damage

DG generators, customer motors, switching equipment and any transformers that are

connected in series between these energy sources.

The potential impact of asynchronous connection of inverter-fed DGs is less certain and

will depend on their individual design. However, if island voltage can be sustained

causing other generators and motors to remain connected, then asynchronous reclosure

must still be avoided.

For the above reasons, all DGs must be quickly disconnected whenever a feeder fault is

detected – before reclosure takes place.

Limitations of DG Self-Clearing Protection Response Times

Based on fault in-feed, DGs cannot distinguish between faults on either side of the utility

feeder breaker or recloser that supplies them. To avoid nuisance trips, some time delay

is required by the DG protection to allow coordination with the faster utility protections to

clear those out-of-zone faults. If that delay is too long, automatic reclosure will be

impaired.

DG anti-islanding protection cannot prevent DG islanding. It can only detect an island

after islanding occurs.

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All passive DG anti-islanding detection methods rely on an unbalance or mismatch

between distributed generation power output and power demands of the connected load

on the isolated island. DG island frequency and voltage can be expected to drift (as per

section ―Expected Frequency and voltage deviations in DG islands‖ above).

Close matching of both active and reactive power would be an extremely unlikely

condition for a prolonged period. Sooner or later, mismatches will cause the voltage or

frequency to drift outside the limits specified in Sections 3.2.13 and 3.2.14.

If by chance the active and reactive power produced by islanded DG happens to be

close to the islanded load demand, then the island may survive for a longer period

before DG self-clearing protections will detect and disconnect the generation.

In some cases, DG self-clearing anti-islanding protections cannot be relied on to

guarantee that the DG will disconnect itself before automatic reclosure takes place. In

those cases, TT and DGEO schemes are required. Refer to appropriate sections for

requirement conditions.

Maximum Detection Times Available for DG Self-Clearing Protections

There are limited time windows available following the formation of an island during which time

DG self-clearing protections have to disconnect the generator before reclosure takes place.

If there is a fault on the feeder at the time the DG island is formed, the DG fault

protection must detect the fault and initiate clearance.

If there is no fault on the feeder at the time the DG island is formed, the DG anti-

islanding protection must detect the island condition and disconnect the generation from

the Distribution System.

Timing diagrams for self-clearing DG protections are shown in Appendix C in Figure 17 and

Figure 18 for a 0.5-second reclosure and for a 1.0 second reclosure, respectively. The times

are based on the following assumptions and constraints:

The assumed maximum fault detection time for Hydro One instantaneous low set

protections is 33ms. More commonly fault detection time will be 16 ms or less.

The reclosure timer is initiated without delay, immediately after the fault is detected by

the Hydro One feeder protection.

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126

The assumed maximum Hydro One fault clearance time is 83 ms after the fault is

detected (5-cycle breaker opening time for oil dead-tank breakers).8

200 ms fault extinction and de-ionization time and/or drop out of motor controls is

required after the last source trips, prior to reclosure.

The DG generator breaker is a 3-cycle breaker.

To prevent interference with automatic reclosure (1 second reclosure):

Self-clearing DG anti-islanding protections must be capable of island detection within

617ms to coordinate with a 1 second reclosure time.

DG fault protection must be capable of detecting all 3-phase and phase-ground faults to

the extreme ends of the supply feeder within 783ms.

For reclosure times longer than 1 second, the protection response times can be

lengthened by equivalent amounts.

TT will be required to speed up DG clearance if the above conditions cannot be met.

To prevent interference with automatic reclosure with a reclose time of 500ms:

Self-clearing DG anti-islanding protections would have to be capable of detecting an

island condition within 117ms.

DG fault protections must be capable of detecting all 3-phase and phase-ground faults to

the extreme ends of the supply feeder within 283ms.

It is expected that DG self-clearing protections cannot selectively and reliably detect fault

and island conditions in such a short time. TT and DGEO will always be required to

speed up DG clearance where 0.5-second reclosure times are used.

Transient Response of DG Islands

Hydro One transient stability studies for some typical synchronous generators have

demonstrated some consistent effects that various generation-to-feeder load ratios have

on DG voltage and speed (frequency).

8 Hydro One clearance time (after fault detection) may be only 50 ms if fast auxiliary relays and 3-cycle

breakers are used.

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These studies have shown that for 50% generator rating to feeder load ratios, generator

frequency declined steadily to about 53 Hz within 1 second. Voltage declined rapidly to

about 75% within about 100 ms and recovered somewhat to about 93% within 1 second.

Such frequency excursion to 53 Hz should ensure that the under-frequency protections,

set as specified in Section 3.2.13 will clear in much less than 1 second (160 ms for

frequency < 59.3 Hz).

Such voltage excursion to 75% may take up to 2 seconds to clear for protection set as

per Section 3.2.14 (50 ≤ V < 88%).

For higher generator rating to feeder load ratios, frequency and voltage does not drift

outside the limits specified in Sections 3.2.13 and 3.2.14.

Generic models for other types of generators - self-fed induction (SFIG), Double-fed

Asynchronous (DFAG), inverters and static power converters are not sufficiently

available to guarantee that DG anti-islanding protections will operate in sufficient time for

all conditions to prevent interference with automatic reclosure.

Based on the above, Hydro One has established a 50% active power unbalance

threshold (DG aggregate capacity / minimum load) above which TT is required to be

used to avoid interference with Distribution System automatic reclosure schemes.

This only applies where automatic reclosure time is 1-second or longer.

Requirements for Transfer Trip

Transfer Trip (TT) is a protection trip signal that is sent from the Hydro One supply source

breaker or recloser to the DG when the DG is required to be disconnected. TT is required to

prevent the adverse effects of DG islands whenever other means cannot reliably do so or are

more expensive. TT is required to quickly disconnect the DG from the Distribution System for

the conditions listed in Section 3.2.16.

TT timing requirements

Refer to Appendix C, Figure 19, and Figure 20 for TT timing requirements.

DGEO Requirements

Distributed Generator End Open (DGEO) is a real time signal that is continuously sent

from the DG to the Hydro One supply source breaker or recloser.

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For ungrounded 3-wire connections, where the DG source cannot contribute ground fault

current, the DGEO signal is derived from all breakers/circuit switchers at the interface

between the DG generation and the PCC necessary to establish DG generation

connectivity. It establishes the connection status of the generation equipment and is

used to block automatic reclosure should DG fail to disconnect after the Hydro One

supply is disconnected. For 3-wire connections that do not have an HVI, connectivity of

the generators will be established by LVI connection logic that mimics all of the possible

generation connection paths.

For 4-wire connections, the DGEO signal must be derived from the DG HVI switch only.

For 4-wire connections all DG ground sources must be connected to the DG side of the

HVI switch and must be disconnected before Hydro One source can be permitted to

energize the feeder. That is because any fault that occurs immediately following Hydro

One energization of the feeder is almost certain to be permanent, and Hydro One low-

set fuse-saving protections are blocked. This allows coordinated clearance of the down-

stream reclosers and fuses with the Hydro One source timed protections.

DGEO requirements are specified in Section 3.2.17.

Low Set Block Signal Requirements

The Low Set Block Signal (LSBS) is a signal that must be sent from the DG to the Hydro One

supply source breaker or recloser, whenever a DG interface transformers (DGIT) is being

energized. This will prevent tripping of the Hydro One supply source during the period when

there is large energizing inrush current to the DGIT. Detection of this signal transition at the

Hydro One supply source breaker or recloser location will cause the most sensitive low-set

(fuse-saving) protection to be temporarily blocked for a short duration, sufficient to allow the

DGIT inrush current to subside.

The LSBS signal can be combined with the DGEO signal through a shared communication

channel from the DG facility to Hydro One.

LSBS requirements are specified in Section 3.2.22.

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Application of TT and DGEO “50% rule” Requirements to DG Islands

The 50% TT rule is intended to preserve the benefits of automatic reclosure following transient

line fault conditions, by ensuring DGs do not interfere with the successful operation of automatic

reclosure schemes. Automatic reclosure is not initiated for other types of permanent faults –

recurring line faults, transformer faults, bus faults or breaker failure condition. In these cases,

providing other adverse impacts are minimal for short-duration DG islanding, self-clearing anti-

islanding protections (over/under voltage and over/under frequency) may be sufficient to

disconnect the generation from the island when frequency and voltage transcend the limits

specified in Sections 3.2.13 and 3.2.14. In all cases, high reliability is required for all protection

schemes that are required to maintain the integrity of the Distribution System.

Typical DG islands that can be formed during transient fault conditions are illustrated in Figure

21 and the following discussion below.

Figure 21: Typical Distribution System with DG Interconnections

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130

Local Area DG Islands

Local Distribution System DG Islands are formed whenever feeder reclosers or TS breakers are

tripped from feeder or line protections interrupting the supply to a portion of the Distribution

System. For each potential local DG island scenario, the aggregate capacity of the islanded DG

must be assessed in relation to the minimum connected islanded load. If the islanded DG

aggregate capacity is greater than 50% of the minimum load of the connected island, then TT

will be required to be sent from the most strategic Hydro One supply location(s) to disconnect

the DG to ensure successful reclosure operations. The TT may be sent directly from the Hydro

One switching device location to the DG or a cascading arrangement may be used to redirect

the TT to the DG via another marshalling location (usually the TS).

Recloser DG Island

A recloser DG island forms when a feeder recloser operates for a feeder fault,

interrupting the Hydro One supply to a section of a feeder to which DG is connected.

In the example, Figure 21, DG2, DG4 and DG5 will be islanded by the adjacent Hydro

One source-side reclosers opening.

Typical automatic reclose times are 1.5 to 2 seconds for reclosers.

To prevent interference with automatic reclosure self-clearing DG anti-islanding

protections must be capable of detecting an island condition within about 1.1 second for

a 1.5 second reclose time and 1.6 second for a 2-second reclose time.

This will be assured if the aggregate capacity of the islanded DG is less than 50% of the

minimum load on the load-side of a feeder recloser. Otherwise, TT will be required to be

sent to disconnect the DG whenever the feeder recloser is opened.

Feeder-breaker DG Island

A feeder-breaker DG island forms when feeder protection operates for a feeder fault,

opening a TS feeder-breaker and interrupting the Hydro One supply to the whole feeder

to which DG is connected.

In the example, Figure 21, DG1 – DG4 will be islanded by the opening of the M2 feeder

breaker.

Typical automatic reclose times are 0.5 to 1 seconds for feeder breakers.

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To prevent interference with a 1.0 second automatic reclose time, self-clearing DG anti-

islanding protections must be capable of detecting an island condition within about 0.6

second. This will be assured if the aggregate capacity of the islanded DG exceeds 50%

of the minimum load on the load-side of a feeder recloser. Otherwise, TT will be

required to be sent to disconnect the DG whenever the TS breaker is open.

To prevent interference with a.0.5 second automatic reclose time, self-clearing DG anti-

islanding protections would have to be capable of detecting an island condition within

117ms. It is expected that DG self-clearing protections cannot selectively and reliably

detect fault and island conditions in such a short time. TT and DGEO will always be

required to speed up DG clearance where 0.5-second reclosure times are used.

If the aggregate capacity of the islanded DG exceeds 50% of the minimum load on the

load-side of the TS breaker, TT will be required to disconnect the DG whenever the TS

breaker is opened.

LV Bus DG island

An LV bus DG island forms when a main terminal line protection operates for an HV line

fault interrupting the Hydro One supply to a DESN TS LV bus to which DG is connected.

In the example, Figure 21, an LV bus DG island would only occur if the bus-tie breaker

BY was open and the L2 line protection opens LV transformer-breaker T2Y interrupting

the Hydro One supply to the Y bus to which DG1 – DG4 are connected.

Automatic reclosure is initiated from the HV line protection and the LV transformer-

breaker Transfer Trip or Remote Trip receive protections. The typical automatic reclose

time for a DESN TS LV transformer-breaker is typically 1 second, but that will only be

completed after the HV line protection at the main terminal TS automatically recloses,

typically in 5 seconds (may be as low as 2 seconds).

To prevent interference with a cumulative 3 second automatic reclosure self-clearing DG

anti-islanding protections must be capable of detecting an island condition within about

2.6 seconds.

This will be assured if the aggregate capacity of the islanded DG exceeds 50% of the

minimum load on the LV bus. Otherwise, TT will be required to be sent to disconnect

the DG whenever the LV transformer breaker and bus-tie breaker are open.

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DESN TS LV island

A DESN TS LV island forms when one or more main terminal line protections operate for

HV line faults, interrupting the Hydro One supply to a DESN TS to which DG is

connected.

In the example, Figure 21, a DESN TS LV would occur if transformer breakers T1B and

T2Y are both opened from operation of HV line protections, isolating all of the DG

connected to the DESN TS (DG1 – DG4).

Automatic reclosure is initiated from the HV line protection and the LV transformer-

breaker Transfer Trip or Remote Trip receive protections. The typical automatic reclose

time for a DESN TS LV transformer-breaker is typically 1 second, but that only after the

HV line protection at the main terminal TS automatically recloses, typically in 5 seconds

(may be as low as 2 seconds).

To prevent interference with a cumulative 3 second automatic reclose time self-clearing

DG anti-islanding protections must be capable of detecting an island condition within

about 2.6 seconds.

This will be assured if the aggregate capacity of the islanded DG exceeds 50% of the

total minimum load on the DESN TS. Otherwise, TT will be required to be sent to

disconnect the DG when all of the transformer breakers are open.

Wide-Area DG Island

A Wide-Area DG island can be formed when one or more main terminal line protections

operate for HV line faults, interrupting the Hydro One supply to all DESN stations and to

any HV-connected DS to which DG is connected.

For a two-circuit supply, both circuits would have to be interrupted to cause a wide area

DG island.

In the example, Figure 21, a wide area DG island would occur if supply to both HV lines

L2 and L2 are interrupted (a double circuit interruption). This is a relatively rare event

but can happen during wind storms or other adverse conditions.

For a single-circuit supply, interruption of the line protection for that circuit would cause a

Wide-Area DG island.

A Wide-Area DG island will occur if there is no TT from the main terminal station to the

DESN station or HV-connected DS or that TT fails causing the DESN station LV

breakers to remain closed. In that case, automatic reclosure of the HV lines will restore

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Hydro One supply to all of the affected Wide-Area, typically in 5 seconds (may be as low

as 2 seconds) provided that there is no back-fed voltage detected on the HV lines by the

HV breaker automatic reclosure schemes.

A Wide-Area DG island may also occur if the next zone (upstream from Terminal

Stations) is tripped. This may occur if the net generation in the wide area network can

sustain the load at the time of occurrence.

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E Appendix E – DGEO & LSBS Design Considerations

The following information is a design consideration for implementation of the DGEO and

LSBS signals for installations utilizing a High Voltage Interrupter or a High Voltage

Disconnect Switch (motorized Load Break Switch). This is for informational purposes only.

HVDS

CLOSE

Control HVDS

CLOSE

HVDS/b

Hydro One

DGn/b

DG2/bDG1/b

Feeder (3-Wire)

DG1

HVDS

Delta

PCC

DG2 DGn

Critical

Load

TT

DGEO

Telecom Tx

Rx

Hydro One

Feeder (4-Wire)

DG1

Wye

PCC

DG2 DGn

Critical

Load

TT

DGEO

Telecom Tx

Rx

HVI

Trip

Trip

Close

Close

pu

T2do

pu

T1dopu

T3do

HVI

CLOSE

Control HVI

CLOSE

HVI/bSpare

SpareSpare

pu

T2do

pu

T1dopu

T3do

HVDS on 3-Wire

HVI on 4-Wire

*HVDS - High Voltage Disconnect Switch

Based on Block ing the Low Set Inst at Hydro One for 5 seconds on a falling edge DGEO signal transition

HVI HVDS

TT Delay DGEO Delay Close Time Close Time PU Delay DO Delay PU Delay DO Delay PU Delay DO Delay

1 16ms 16ms 100ms 0ms 0ms 1s 0ms 0ms 6s

2 16ms 16ms 1s 0ms 0ms 1s 0ms 0ms 6s

3 30ms 250ms 100ms 0ms 0ms 1s 0ms 0ms 6s

4 30ms 250ms 1s 0ms 0ms 1s 0ms 0ms 6s

Example

#

Teleprotection Delay Timer T1 Timer T2 Timer T3

Figure 22: DGEO & LSBS Design Consideration

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F Appendix F – Example of a Sequence of Events During Fault Conditions

The following two figures are a typical sequence of events during abnormal conditions, for both a transient fault and a permanent fault. Note: These diagrams assume that the DG facility requires Transfer Trip

and a HVI. This is for informational purposes only.

Figure 23: Sequence and Timing Diagram for Transient Faults

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Figure 24: Sequence and Timing Diagram for Permanent Fault

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G Appendix G – Confirmation of Verification Evidence Report (COVER Form)

The following is HONI‘s COVER Form. An updated version may be available and will be provided by HONI.

CONFIRMATION OF VERIFICATION EVIDENCE REPORT (COVER) [Distribution Connected Generation – (DCG)]

(Instructions provided on last Page)

Section 1 FACILITIES INFORMATION

NAME OF CUSTOMER

NAME OF FACILITY

PROPOSED ENERGIZATION DATE

HYDRO ONE OPERATING DESIGNATION

CLAIM NOTIFICATION

(Investment Planning #)

SUPPLY FEEDER DESIGNATIONS

Section 2 CONTACT INFORMATION

CUSTOMER CONTACT HONI COVER COORDINATOR CONTACT

Print Name:

Title:

Date:

Tel. #:

Email:

Print Name:

Title:

Date:

Tel. #:

Email:

[COVER - page 1 of 8]

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Section 3 VERIFICATION-PROTECTION & CONTROL

Protection Group to verify: A, B, or A&B

Legend: C = Confirm

Results: P = Pass, F = Fail, N/A = Not Applicable

Pro

tect

ion G

roup

To v

erif

y

Leg

end

Res

ult

s

Init

ials

Dat

e

mm

/dd/y

yyy

Note

#

Is commissioning in compliance with the submitted

Commissioning plans?

Are reviewed relay settings applied?

Confirm that the following protection systems, as

applicable, have been verified to function as per the

design:

NOTE: Tests marked with an asterisks (*) require Hydro One

staff coordination

Line Protection

HV Breaker Failure Protection and Reclose

LV Breaker Failure Protection and Reclose

Transformer Differential

Transformer Backup Protection

Under and Over Frequency

Under and Over Voltage

Transfer Trip / Remote Trip *

Pilot Wire Protection *

Blocking Scheme Circuits *

Generation Rejection & Load Rejection Circuits *

Reverse Power

Gen. Prot. That trip HV Sync Breakers

Instrument Transformer (eg. CTS + CCVTs, etc.)

Monitoring Equipment (eg. DFR, SER, etc.)

Other (Specify)


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Section 4A TELEMETRY TESTS BEFORE ENERGIZATION AT CUSTOMER OWNED TS

Confirm the following SCADA telemetry quantities,

where applicable:

Test Needed: D = to be Done

Legend: C = Confirm; Results: P = Pass, F = Fail

All Parts: N/A = Not Applicable

Tes

t

Nee

ded

Leg

end

Res

ult

s

Init

ials

Dat

e

mm

/dd/y

yy

y

Note

#

HV MW per transformer

HV MVAR per transformer

HV Phase to Phase Voltages (R, W, B)

LV MW per LV Bus

LV MVAR per LV Bus

LV Phase to Phase Voltages (R, W, B)

HV Under-Load Tap Changer Positions

HV Disconnect Switches/HV Circuit

Switchers/Breakers Open/Close Status

LV Transformer & Bus Tie Breakers Open/Close

Status

LV Capacitor Breakers Open/Close Status

Common Protection Trip Alarm each HV Circuit

Other (specify)

Section 4B TELEMETRY TESTS BEFORE ENERGIZATION AT CUSTOMER OWNED GS

Confirm the following SCADA telemetry quantities,

where applicable

Test Needed: D = to be Done

Legend: C = Confirm; Results: P = Pass, F = Fail

All Parts: N/A = Not Applicable Tes

t N

eed

ed

Leg

end

Res

ult

s

Init

ials

Dat

e

mm

/dd

/yy

yy

No

te #

MW Flows and Directions

MVAR Flow and Directions

Phase to Phase Voltages

HV switchers/HV breakers/Bus Tie Breakers

Open/Close Status

HV Line Disconnect Switches Open/Close Status

Synchronizing Breakers Open/Close Status

AVRs, PSSs status

Generation Rejection Selection Status

LV Breakers/Switchers, Open/Close Status

LV Synchronizing Breakers, Open/Close Status

Protection Trip Alarms

Other (specify)


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Section 5 CONFIRMATION OF VERIFICATION-POWER EQUIPMENMT

Legend: C = Confirm, W = Witness

Result: P = Pass, F = Fail

All Parts: N/A = Not Applicable

Note, some of the following verification may require HONI staff witnessing.

Leg

end

Res

ult

Init

ial

Dat

e

mm

/dd/y

yyy

Note

#

Verify the HV disconnect switches/circuit switchers are suitable as an

isolation point per Utility Work Protection Code?

NOTE: Any future modifications to the isolation device(s) used to provide

supporting guarantees to HONI staff under the Utility Work Protection Code

must be re-witnessed by HONI personnel.

Confirm correct operation of the HV disconnect switches/circuit

switchers/breakers

Is closing time within manufacturer’s specification?

Is opening time within manufacturer’s specification?

Are the specified HV surge arrestors installed?

Confirm the power transformer Doble test results are within specification

Confirm power transformers connected correctly as per the design.

Confirm the DC system installed (ie battery, charger, dc panel, dc

monitoring)? Verified

Does the HV equipment (ie, disconnect switches, circuit switchers,

breakers, CVTs, CTs) have the appropriate voltage class and current

ratings as per the submitted Single Line Diagram?

Other (specify)

Name of Hydro One Witness:

Section 6 ELECTRICAL SAFETY

Legend: SD = Supporting Document, N/A = Not Applicable

Leg

end

Dat

e

mm

/dd/y

yy

y

Prior to energizing any new or modified customer or generator facilities, Electrical Safety Authority (ESA) must provide a Temporary Connection Authorization (Ontario Electrical Safety Code Article 2-014). Attach document.

Prior to final in-service of new or modified customer or generator facilities, ESA must provide Connection

Authorization (Code Article 2-012). Attach document.

All customers must provide a letter signed and stamped by a Professional Engineer registered in the province of

Ontario stating that their equipment and installation meets CSA and/or other applicable electrical safety standards, prior to ready for Service Date. Attach document.


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NOTES: (For Sections 3, 4A or 4B, 5 & 6)

#: Comments: COVER Coordinator Concurrence To Connect:

Date Action Resolved: (dd/mm/yyyy)

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

By signing* this form, the customer

acknowledges that all required verifications

specified under this COVER document have

been completed and that the customer facility

design and operation meets the minimum

standards for customer facilities connected to a

distribution system, as per the Distribution

System Code.

Signature of Customer Representative (Note : Must be P. Eng)

Print Name:

Title:

Date:

Part I Completed COVER Coordinator Initials

*After signing the COVER, the customer shall submit it to the COVER coordinator with a copy to the Account Executive.

The COVER Coordinator has reviewed the

customer’s Certified COVER document and the

customer’s facility may be connected to the grid,

subject to Controlling Authority’s final review.

Signature of COVER Coordinator

Print Name:

Title:

Date:

The COVER coordinator shall forward (scan/fax) the completed document to the Controlling Authority to initiate the connection (for OGCC controlled distributed generators, the OGCC is the controlling authority. For other feeders the controlling authority will be Provincial Lines). The COVER coordinator shall contact (phone) the Controlling Authority, to notify him/her of the completed COVER. The COVER coordinator will ensure this document is placed within the Distribution Connection Agreement.


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Section 7 CONFIRM ON POTENTIAL/ON LOAD CHECKS AT RATED SYSTEM

VOLTAGE

Legend: C = Confirm, W = Witness Result: P = Pass, F = Fail

All Parts: N/A = Not Applicable Leg

end

Res

ult

Init

ial

Dat

e

mm

/dd/y

yyy

Note

#

Are phasor (X-Watt meter) readings completed and analyzed by the

customer for Protection listed in Section 3?

Are phasor (X-Watt meter) readings completed and analyzed by the

customer for SCADA quantities listed in Section 4?

On Load SCADA Values confirmed consistent with test(s)

performed in Section 4A or 4B?

NOTES: (For Section 7)

#: Comments: COVER Coordinator

Concurrence:

Date Action Resolved:

(dd/mm/yyyy)

1.

2.

3.

4.

I/we acknowledge the completion of the COVER as noted and the deficiencies identified in the “NOTES” section have been resolved.

Signature of Customer Representative (Note: Must be P. Eng,)

Print Name:

Title:

Date:


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Section 8 TEST SUMMARY REPORTS

In accordance with the Distribution System Code, Appendix F, for a Generation facility of Small size (pg.13), Mid size (pg.21), and Large size (pg.28), the Customer shall, at Hydro One's request, provide Hydro One with a

summary of testing results, including any certificates of inspection or other applicable authorizations or approvals

certifying that any of the Customer's new, modified or replacement facilities have passed the relevant tests and comply with all applicable instruments and standards referred to in the code. This information will be kept on file

for a period of (7) years by the Customer.

DISTRIBUTION LIST (WHEN ALL SECTIONS ARE COMPLETED):

Distribution Customer Business Relations Controlling Authority Customer Agent

Distribution Records (original) HONI COVER Coordinator


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Customer Instructions for Completing the COVER form (DCG)

PART 1: PLAN

Step 1: Customer Information

Complete Facility and Customer Contact Information of the COVER Form by completing the highlighted

portions of Sections 1 & 2.

Step 2: Identify the Tests that the Customer Intends to Conduct

Complete Highlighted portions (Protection Group and Legend columns) of Sections 3, where applicable

Complete Highlighted portions of Section 4A or 4B (Test Needed and Legend columns)

Complete Highlighted portions of Sections 5 (Legend column) and 6 (Date Received column)

Note: The design review must be finalized prior to completing this step.

Step 3: Hydro One’s COVER Coordinator Review

Return COVER Form by email to the HONI COVER Coordinator listed in Section 2

The COVER coordinator will review the proposed and a respond to the acceptability of the proposed COVER

tests within 5 business days.

Note: The commissioning plan review must be finalized prior to commencing testing for the next step.

PART 2: PRE-ENERGIZATION

Step 4: Completion of Testing and Resolution of all Comments

Complete all applicable testing in Sections 3, 4A or 4B, 5 & 6.

Sign off the COVER, in section 6, by a Customer P.Eng Representative, and submit it to the COVER

Coordinator and Account Executive.

The COVER coordinator will review the certified COVER and recommend to the Controlling Authority (CA)

for connection to the grid by signing section 6 (for OGCC controlled distributed generators, the OGCC is the controlling authority. For other feeders the controlling authority will be Provincial Lines.)

Section 7 testing can only proceed when all salient comments have been resolved and tests completed for

Sections 3 to 6.

PART 3: POST-ENERGIZATION

Step 5: Final Potential and On-load Checks

Controlling Authority will provide authorization to connect to the grid (for OGCC controlled distributed

generators, the OGCC is the controlling authority. For other feeders the controlling authority will be Provincial

Lines.)

Complete and sign Section 7 when all parts of the COVER form are complete. (Note: cross readings to be performed within 5 business days of placing load on station)

Summary of testing results and certificates must be kept on file for a minimum period of 7 years by the

Customer (as indicated by IESO Market Rules, Chp.4, 5.1.3). Hydro One Networks Inc. may require this

information, on an exception basis.


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H Appendix H – Distribution Policy – Metering for Embedded Generators NOP 041

The following is HONI‘s Metering for Embedded Generators NOP 041 Policy. It contains the metering requirements for DG interconnection to HONI‘s distribution system.

Hydro One Dg Technical Interconnection Requirements Distribution Interconnections

Technology

Transcript of Hydro One Dg Technical Interconnection Requirements Distribution Interconnections