Recommended Practice – Detecting Unintended Islands -...

IEEE P1547.8™/D6 January 2014

IEEE P1547.8TM/D6 Draft Recommended Practice for Establishing Methods and Procedures that Provide Supplemental Support for Implementation Strategies for Expanded Use of IEEE Standard 1547 SponsorStandards Coordinating Committee 21 of theIEEE Standards Association Standards Board

Copyright © 2014 by the Institute of Electrical and Electronics Engineers, Inc.Three Park AvenueNew York, New York 10016-5997, USA

All rights reserved.This document is an unapproved draft of a proposed IEEE Standard. As such, this document is subject to change. USE AT YOUR OWN RISK! Because this is an unapproved draft, this document must not be utilized for any conformance/compliance purposes. Permission is hereby granted for IEEE Standards Committee participants to reproduce this document for purposes of international standardization consideration. Prior to adoption of this document, in whole or in part, by another standards development organization, permission must first be obtained from the IEEE Standards Association Department ([email protected]). Other entities seeking permission to reproduce this document, in whole or in part, must also obtain permission from the IEEE Standards Association Department.

IEEE Standards Association Department445 Hoes LanePiscataway, NJ 08854, USA

Secretary’s note to working group (items below should be completed prior to ballot release). 1) Per IEEE review, it was requested to determine if all the bibliographic entries are absolutely

needed. Can the working group/subgroup review which entries in all the separate bibliographies are the most pertinent that would still provide the P1547.8 reader the overall information and identify the authors so the reader may then consider those entries and then further conduct their own literature search to find additional citations by the authors named in the P1547.8 bibliographies. All the citations/bibliography entries within each clause and Annex need to be moved to the P1547.8 Bibliography (Annex A).

2) All authors of P1547.8 figures need to reply to [email protected] and [email protected] that they created the figures (or tables) for use by IEEE in P1547.8, and authors need to provide the native files (i.e., the editable/original file) if not already embedded in P1547.8 D6. If the figures are copied, the P1547.8 provider needs to work with Matt and Tom to get a copyright release from the originator.

3) All authors any P1547.8 text (or tables) that is copied from other sources need to reply to [email protected] and [email protected] to establish if copyright release is needed.

Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 1

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Table of Contents 1. Overview...................................................................................................5

1.1. Scope....................................................................................................51.2. Purpose.................................................................................................51.3. What this document provides...............................................................51.4. Word usage...........................................................................................6

2. Normative references...............................................................................73. Definitions and acronyms.........................................................................7

3.1. Definitions.............................................................................................73.2. Acronyms..............................................................................................7

4. Interconnection technical specifications and requirements.....................74.1. General requirements...........................................................................8

4.1.1. Voltage regulation............................................................................84.1.1.1. Introduction (Background information – knowledge base)......84.1.1.2. Recommended practices..........................................................84.1.1.3. Mitigation of voltage fluctuations............................................94.1.1.4. Other recommended practices for interconnection studies.....114.1.1.5. Bibliography for the Voltage Regulation clause.......................12

4.1.2. Integration with area EPS grounding...............................................124.1.3. Synchronization................................................................................134.1.4. Distributed resources on distribution secondary grid and spot

networks...........................................................................................134.1.5. Inadvertent energization of the area EPS........................................134.1.6. Monitoring provisions.......................................................................134.1.7. Isolation device.................................................................................134.1.8. Interconnect integrity.......................................................................13

4.1.8.1. Protection from electromagnetic interference.........................144.1.8.2. Surge withstand performance..................................................144.1.8.3. Paralleling device.....................................................................14

4.2. Response to area EPS abnormal conditions........................................................144.2.1. Area EPS faults.................................................................................144.2.2. Area EPS reclosing coordination......................................................184.2.3. Voltage..............................................................................................194.2.4. Frequency.........................................................................................204.2.5. Loss of synchronism.........................................................................214.2.6. Reconnection to area EPS................................................................21

4.3. Power Quality.......................................................................................214.3.1. Limitation of DC injection.................................................................21


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4.3.2. Limitation of flicker induced by the DR............................................214.3.3. Harmonics........................................................................................21

4.4. Islanding...............................................................................................214.4.1. Unintentional islanding....................................................................214.4.2. Intentional islanding.........................................................................23

5. Interconnection test specifications and requirements.............................235.1. New voltage regulation tests................................................................235.2. EMI Test...............................................................................................245.3. New short circuit behavior test............................................................245.4. New loss of load behavior test..............................................................24

6. Monitoring, Information Exchange, and Control (MIC)...........................246.1. Communications for DR Functions.......................................................256.2. Communication Technologies for DR Systems.....................................256.3. Different Communication Requirements for Different DR Scenarios...26

6.3.1. Categorization of Information Exchanges by EPS Sensitivity..........296.3.2. Size of Single or Multiple DR systems..............................................296.3.3. Types of Communications between the EPS Operator and DR Systems

..........................................................................................................296.3.4. EPS Operator Monitoring of Real Power, Reactive Power, and Voltage

at the PCC.........................................................................................306.3.5. DR and EPS Protection.....................................................................306.3.6. Communications for Autonomous DR Functions..............................316.3.7. Direct Management of DR Systems..................................................32

7. Multiple DR in Area EPS Management.....................................................327.1. Interference with Anti-Islanding Protection.......................................................33

7.1.1. Mix of Inverter-based and Rotating DR in Area EPS........................347.1.2. Conflicts in Island Detection............................................................347.1.3. Interference of Active Anti-Islanding...............................................34

7.2. Voltage Oscillation due to DR Control Interaction...............................................357.3. Group Variation of DR Output.......................................................................35

7.3.1. Testing..............................................................................................357.3.2. Best Practices...................................................................................35

7.4. Group Trip on Voltage or Frequency Excursions.................................................367.4.1. Best Practices...................................................................................36

7.5. DR as a Tool for Managing Power Systems.......................................................368. Functionality of the DR island system......................................................41

8.1. Area EPS-connected mode (normal parallel operation).......................428.2. Transition-to-island mode.....................................................................42


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8.3. Island mode..........................................................................................428.4. Reconnection mode..............................................................................438.5. Load requirements and planning..........................................................43

8.5.1. Reactive power considerations.........................................................438.5.2. Transformers....................................................................................448.5.3. Motors..............................................................................................448.5.4. Lighting............................................................................................448.5.5. Load power quality...........................................................................448.5.6. Compatibility of grounding among the DR, transformer, and EPS. .458.5.7. Frequency regulation.......................................................................458.5.8. EPS power quality............................................................................45

9. Extension beyond 10 MVA........................................................................47Annex A (Informative) -- Bibliography.................................................................49Annex B (Informative) -- DER Management Interaction Processes.....................52Annex C (Informative) -- Voltage Regulation.......................................................57Annex D (Informative) -- DR Monitoring and Control Concepts..........................66Annex E (Informative) -- Group Behavior...........................................................99Annex F (Informative) -- DR and Utility Protection Best Practices......................103Annex G (Informative) -- North American Distribution System Design and

Operating Practices..................................................................................125Annex H (Informative) -- Voltage and Frequency Trip Coordination with Area EPS

.................................................................................................................. 160Annex I (Informative) -- Response of Non-Traditional Generators under Fault

Conditions.................................................................................................164Annex J (Informative) – “Frequency Feedback Method with Step Injection”

(Japanese Experience with new Anti-islanding Technology of Inverter-based DR)............................................................................................................171

Annex K (Informative) – Advanced DR Functions for Supporting the EPS..........180Annex L (Normative) -- Glossary..........................................................................192


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P1547.8™/D 6.0 Draft Recommended Practice for Establishing Methods and Procedures that Provide Supplemental Support for Implementation Strategies For Expanded Use of IEEE Standard 1547

1. Overview1.1.Scope This recommended practice applies to the requirements set forth in IEEE Std 1547 and provides recommended methods that may expand the usefulness and uniqueness of IEEE Std 1547 through the identification of innovative designs, processes, and operational procedures.

1.2.Purpose The purpose of the methods and procedures provided in this recommended practice is to provide more flexibility in determining the design and processes used in expanding the implementation strategies used for interconnecting distributed resources with electric power systems. Further, based on IEEE Std 1547 requirements, the purpose of this recommended practice is to provide the knowledge base, experience, and opportunities for greater utilization of the interconnection and its applications.

The purpose of the document is to also include system integration recommendations. IEEE 1547 was established based on its requirements being satisfied at the PCC. This document considers effects of, and recommended practices for, DR interconnection based on considerations beyond the PCC. This document also addresses recommendations that address DR supporting the overall improvement of the area and local EPS functioning. The proposed changes in IEEE 1547.a are also included.

1.3.What this document provides This document provides approaches for the application of DR interconnected with the grid considering IEEE 1547 requirements on an overall system-wide, DR-system integration basis. This document provides recommendations addressing DR interconnection system-level potential adverse effects, and, opportunities for EPS improvement, considering: the DR technology capabilities, the interconnection technology capabilities, the operations of the DR, the operations of the area EPS, the operations of the local EPS, the effects on power quality (voltage and frequency concerns), the DR interconnection response to abnormal area EPS conditions (voltage, frequency, faults, etc.), the advanced capabilities of DR functions for supporting area EPS operations, and, the potential for DR to increase reliability and efficiency of electricity delivery and grid operations.

This document provides, for example, considerations of multiple PCCs, whereas IEEE 1547 does not address multiple PCCs on a given Area EPS. When there is a large total amount of DR on an area EPS (either one PCC or multiple PCCs), commonly called “high penetration,” penetration condition, that may cause adverse impacts, or possible benefits. Such potential adverse impacts could affect not only the Area EPS but also the other DR connected to the Area EPS. This document provides recommendations on how to consider these impacts as well as additional overall system-level issues, for example covering the close-proximity feeder, and possibly the area EPS substation serving that feeder. System-wide benefits are also considered in this document, e.g., voltage and frequency ride-through. The overall system viewpoint takes into account the interaction of multiple DR within an Area EPS, and the effects of multiple DR on the Area EPS, including the goal to provide recommendations covering additional DR that are proposed or installed in close proximity to existing DR installations. That same goal is applicable for large installations which, from an impact point of view, look similar to high penetration of smaller DR units.

This document provides recommended practices and some guidance as how to address DR interconnection design, systems integration, and EPS operations. That includes what may be done for area EPSs having existing DR interconnections to support the additional DR interconnections on that area EPS. And, additional system of systems approaches are considered in 1547.8, e.g.: advanced system protection including unintentional islanding; advanced


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communications, and, monitoring, information exchange and control (MIC; the IEC 61850-7-420 and IEC 61850-90-7 information model for the advanced DR functions (see Annex K) and the possible updating of IEEE 1547.3); microgrids; and, Smart Grid concepts including use of IEEE Std 2030. The new revision in IEEE 1547.a are also incorporated into this document.

There are potential benefits in addressing DR interconnection of a single PCC beyond the 10 MVA limit and to address other stated limits of IEEE 1547. The approach of this document is that all clauses apply to all DR interconnection sizes unless otherwise stated.

There are no absolute (prescribed) limits on high penetration for a given area EPS feeder or circuit in this document. The amount of DR interconnection that can be accommodated at one feeder or circuit on an EPS can vary greatly from one location to another location. There may be a different total amount of all DR interconnection for all PCCs for similar feeders or circuits on different area EPSs for various reasons, e.g., technology types and operating principles. The upper limits of the total DR for all PCCs in each area EPS system can be studied based on the IEEE 1547.7 standard.

1.4.Word usage This 1547.8 standard was established as a “Recommended practice: a document in which procedures and positions preferred by the IEEE are presented” [IEEE-SA Standards Board Operations Manual]. IEEE standards documents are classified as [IEEE Standards Style Manual]:

— Standards: documents with mandatory requirements. Mandatory requirements are generally characterized by use of the verb “shall,” whereas recommended practices normally use the word “should.” See the IEEE Standards Style Manual for further information.

— Recommended practices: documents in which procedures and positions preferred by the IEEE are presented.

— Guides: documents in which alternative approaches to good practice are suggested but no clear-cut recommendations are made.

Trial-Use documents: publications in effect for not more than two years. They can be any of the categories of standards publications listed above.

The following discusses certain word usage in IEEE standards [IEEE Standards Style Manual].

The word shall indicates mandatory requirements strictly to be followed in order to conform to the standard and from which no deviation is permitted (shall equals is required to). NOTE—The use of the word must is deprecated and shall not be used when stating mandatory requirements; must is used only to describe unavoidable situations.

The use of the word will is deprecated and shall not be used when stating mandatory requirements; will is only used in statements of fact.

The word should indicates that among several possibilities one is recommended as particularly suitable, without mentioning or excluding others; or that a certain course of action is preferred but not necessarily required (should equals is recommended that).

The word may is used to indicate a course of action permissible within the limits of the standard (may equals is permitted to).

The word can is used for statements of possibility and capability, whether material, physical, or causal (can equals is able to).


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2. Normative references The following referenced documents are indispensable for the application of this document (i.e., they must be understood and used, so each referenced document is cited in text and its relationship to this document is explained). For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments or corrigenda) applies.

IEEE Std 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems

IEEE Std 1547a Standard for Interconnecting Distributed Resources with Electric Power Systems – Amendment 1

IEEE Std 1547.1 Standard for Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems

IEEE Std 1547.2 Application Guide for IEEE 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems

IEEE Std 1547.3 Guide For Monitoring, Information Exchange, and Control of Distributed Resources Interconnected with Electric Power Systems

IEEE Std 1547.4 Guide for Design, Operation, and Integration of Distributed Resource Island Systems with Electric Power Systems

IEEE Std 1547.6 Recommended Practice For Interconnecting Distributed Resources With Electric Power Systems Distribution Secondary Networks

IEEE Std 1547.7 Guide to Conducting Distribution Impact Studies for Distributed Resource Interconnection

IEC 61850-7-420 Communication networks and systems for power utility automation - Part 7-420: Basic communication structure - Distributed energy resources logical nodes

IEC/TR 61850-90-7 Communication networks and systems for power utility automation - Part 90-7: Object models for power converters in distributed energy resources (DER) systems

3. Definitions and acronyms For the purposes of this document, the following terms and definitions apply. The IEEE Standards Dictionary: Glossary of Terms & Definitions should be consulted for terms not defined in this clause.1

3.1.Definitions High Penetration of DR: From the perspective of local protection and voltage control of the Area EPS and the DR, high penetration can be defined as the point at which related modifications to the Area EPS are required. When DR penetration is low there is no requirement to modify the Area EPS. As the amount, location and type of generation connected to the Area EPS changes, protection and voltage control issues arise. This occurs as the distribution system evolves from radial to non-radial.

3.2.Acronyms Acronyms are yet to be added by each subgroup

4. Interconnection technical specifications and requirements

1 The IEEE Standards Dictionary: Glossary of Terms & Definitions is available at http://shop.ieee.org/.Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 7

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Clause 4 of this document is structured using the same outline as Clause 4 of IEEE Std 1547. For each IEEE Std 1547 clause 4 subclause, recommended practices are provided.

4.1.General requirements4.1.1. Voltage regulation The DR shall not actively regulate the voltage at the PCC without consent from the Area EPS. The area EPS may require voltage and/or VAR support from DR. The DR shall not cause the Area EPS service voltage at other local EPSs to go outside the requirements of ANSI C84.1, except as permitted by the Area EPS operator. Local regulatory requirements may be imposed.

4.1.1.1. Introduction (Background information – knowledge base)These requirements imply that even without active voltage regulations by the DR, the operations of DR may impact the voltages at different locations of the Area EPS. These impacts can be positive, improving voltage regulations in the Area EPS, but also can be negative, presenting a number of challenges to the voltage support in the Area EPS.

Basic background information supporting Clause 4.1.1 of IEEE 1547-2003 [1]is given in IEEE 1547.2 [2], Clause 8.1.1. This Clause addresses the possible impacts of the DR on the Area EPS voltage regulation and emphasizes following issues related to Voltage Regulation in Area EPS with DR:

Relative weakness or stiffness of the Area EPS at the point of interconnection of the DR, and the influence of DR output changes on Area EPS voltage (see Appendix C).

Impact of DR operations on voltage-regulating devices of Area EPS, which may have a potential of creating either a too low, or a too high voltage.

Voltage imbalance due to single-phase DR

Intermittent operations of DR, which may result in unacceptable voltage fluctuations and excessive operations of voltage-regulating devices in the Area EPS

Improper regulation during reverse power flow conditions, which may result in either a too high, or a too low voltage.

Additions to background information given in IEEE 1547.2 are presented in Annex C.

4.1.1.2. Recommended practices

Coordination of DR with EPS voltage/var controlling devices under steady-state conditionsThe presence of DR in distribution circuits change the power flow in the upstream from the DR portions of the circuits and may change the voltage profiles along the circuits, depending on the location of the DR. If the DR is located electrically close to the power source or in a relatively strong/stiff Area EPS location, the voltage profile will not change much. If the DR is located in an electrically remote or weak Area EPS location, the injection from the DR may change the voltage profile. If the EPS voltage controlling devices use line-drop compensation (LDC), their setpoints will change with the change of the DR injections. In the case of a DR interconnected close to the downstream side of a voltage regulator, the voltage reduction due to the reaction of the LDC to the DR injection will lead to low voltages along the distribution circuits. In the case of a DR remote from a regulator, the DR injections may raise the voltages above the desired levels in the vicinity of the DR, and the LDC may compensate the increase in voltage by lowering the upstream voltages. However, in some cases, the voltage reduction due to the LDC reaction to the DR injection may be excessive and may result in too low voltage in some intermediate points of the circuits. Therefore, the selection of the voltage controller settings in the cases with DR may be different from the conventional approach, which is based on the maximum-minimum load conditions. Considering customized modes of voltage controller settings for the “With DR” and “No DR” can be recommended. The customization can be programmed by the operator, or by a DMS application.Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 8

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Under conditions with DRs in distribution, the settings of the EPS voltage and var controllers should satisfy the situations, when the DR are OFF and when they are ON in different practical combinations. This may mean that the settings should be changed in a near-real time fashion. This requirement encourages the use of an advanced Volt/var control application, possibly implemented via a Distribution Management System (DMS), or a feeder-level control.

If the DRs are capable of generating/absorbing reactive power, their controllers may be set to compensate for voltage changes by coordination of the reactive power injections with the active power injections. This coordination can be EPS-specific and should prevent undesirable interaction between regulators.

If distribution automation is implemented, the settings of the EPS voltage-controlling devices, as well as the setpoints of the DR controllers can be remotely adjusted to better fit the near-real-time situations.

If the coordination of the existing EPS voltage-regulating devices with the DR controllers is insufficient to provide the desired voltage regulating objectives, installation of additional devices should be considered.

If the desired results cannot be achieved by the coordination of the reactive and active power injections due to the existing X/R ratio, adding additional series reactors and or supplemental dynamic sources of reactive power could be considered. The addition of series reactors for this purpose is currently a non-standard practice with ramifications and will need to be studied.

Reconfiguration of the EPS circuits may change the impact of DR on EPS voltage regulation. Therefore, timely updates of the EPS connectivity model and of the DR impact on the EPS voltage regulation, as well as corresponding adjustments to the volt/var related operations are needed.

4.1.1.3. Mitigation of voltage fluctuations

Prevent excessive operations of EPS voltage-controlling devices.The reactions of the voltage controlling devices with load tap changers (LTCs) to the fluctuations depend on the relative system weakness at the voltage controlling device upstream impedance between the voltage controlling device and the EPS power source, on the steepness (droop) of the LDC settings, on the voltage control bandwidth, and on the time delay of the controllers. The greater the relative system weakness upstream impedance, the greater is the impact of the DR kW and kvar fluctuation on the supply-side voltage and, therefore, on the number of LTC operations. These impacts should be taken into account, when selecting the settings of the LTC controllers. When defining the LDC settings, there are the following choices:

No LDC at all.

Different ratios for active and reactive power LDC

The steeper the LDC settings, the more sensitive the LTC controllers are to the changes of the powers. On the other hand, the LDC may be needed for the operations without the DRs and with the DRs in remote locations. If the LDC settings are selected for long-term time interval, they should satisfy the steady-state conditions with and without the participation of DR and the intermittent conditions with the DR. Hence, a compromise solution should be sought. In this solution, in addition to the steady-state conditions, the expected changes of the DR reactive powers compensating for the impacts of the active power should be taken into account. For some DR, the compensating kvars are smaller than the changes of the kW. Hence, the droop for the reactive component of the LDC, which is supposed to compensate for the active component of the LDC, should be greater than the active component. For other DRs (e.g. connected to the primary of an UG circuit), the compensating kvars are the same or greater than the changes of the kWs. In this case, to compensate the active LDC component by the reactive LDC component, the droop for reactive compensation should be the same or smaller.

The LTC controller bandwidth is defined by the step size of the LTC and by the voltage and power measurement errors. The bandwidth is typically set to avoid excess LTC operations. The voltage fluctuations at the place of voltage measurements by the LTC controller are proportional to the impedance upstream from the measurement


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place. In many cases, this impedance is small, and so are the voltage fluctuations. If the voltage fluctuations at the input of the controller are smaller than the controller’s bandwidth, these fluctuations would not significantly increase the number of LTC operations, and the increase of the bandwidth would not be needed.

Reduction of the number of LTC operations due to voltage fluctuations can be achieved if the time delay of the voltage controller is considerably increased, at least in the range of several minutes. Such an increase would have a significant negative effect on voltage quality at all times, with and without DRs.

It is desirable that the voltage setpoints of the LTC controllers are adaptable to different operating conditions. The solution may be in the implementation of the Integrated Volt/Var control as a DMS function, which would adjust the voltage settings of the EPS voltage-controlling devices based on the near-real-time situations.

Compensate voltage fluctuations caused by intermittent operations of DR.Operation of the DR at constant power factor, by definition, means that the reactive power changes in absolute magnitude in proportion to the real power. With the proper selection of power factor, voltage fluctuations caused by DR can be mitigated.

The constant power factor mode of DR operations performs differently for leading and lagging power factors. When the DR generates reactive power and keeps constant power factor, the reduction of generated kW coincides with the reduction of the generated kvar. Both factors lead to increase of the voltage drop in the upstream portions of the circuits and, consequently, to voltage reduction at the end-user locations. If the DR absorbs reactive power and keeps constant power factor, the reduction of the generated kW coincides with the reduction of the absorbed reactive power. The former factor increases the voltage drop, while the latter reduces the voltage drop. These opposite impacts reduce the fluctuation of voltages caused by the fluctuations of the DR kW. The degree of such compensation of changes in voltage drops depends on the PF settings, which in turn, depend on the X/R ratio. The constant settings of the DR absorbing power factor can be determined for some average or most likely conditions, taking into account the expected operations of the multiple volt/var impacting devices, supporting an open-loop control [3].

If the DR is following a reactive power setpoint, the reactive power does not change to compensate for the changes of voltage caused by the fluctuations of the active power.

Another method for compensation of the voltage fluctuations is the “constant voltage” mode of operations of the reactive power sources. In this case, the reactive power would be automatically adjusted to provide the compensation of the voltage fluctuations, caused by local and other causes, regardless of the initial (leading or lagging) modes of operations, thus providing closed-loop compensation [4]. However, although constant voltage regulation can be highly effective in mitigating voltage variations, there are several issues making implementation challenging, including: adverse interaction between voltage regulators regulating closely linked buses, and excessive contribution of DR to cancellation of normal voltage variations during the daily load cycle.

It must be noted that the ability of a DR to change voltage via reactive power depends on the reactance of the circuits upstream from the DR. The smaller is the reactance, the smaller is the impact of the DR’s reactive power on the voltage. The impact of reactive power injections of DRs on voltages is also limited by reactive power capability of the DRs. If the reactive power capability of the DR is insufficient to reduce the voltage fluctuations to the acceptable level, additional fast-acting voltage conditioning means are to be considered. If the desired results cannot be achieved by the coordination of the reactive and active power injections due to the existing X/R ratio, adding additional series reactors could be considered.

The voltage settings for the DRs should be acceptable for both: steady-state and intermittent operations.

If an Integrated Volt/Var control application of DMS is implemented, the settings of the DR controllers can be either remotely adjusted or updated voltage schedules can be downloaded to better fit the near-real-time situations.

Addressing voltage imbalance


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Single-phase DRs superimpose an unbalanced power flow over the initial (without DR) three-phase power flow, which may be unbalanced by itself [from the original installation]. The injection of the DR may either reduce the initial imbalance of the power flow, if it is connected to a more loaded phase, or may increase the imbalance, if it is connected to a less loaded phase. If the single-phase DRs are connected to the medium voltage (primary) side of the distribution circuits, the change in voltage imbalance is caused by the incremental voltage drop in the primary feeder. If the single-phase DRs are connected to the secondary (low voltage) distribution circuits, the impact of the DR on the voltage imbalance depends on the circuit parameters and on the type of connection of the distribution transformers. The most significant impacts on the voltage imbalance in the secondaries are expected in cases with the DR connected to open-delta distribution transformers and to distribution transformers with a central tap.

The interconnection studies should take into account the possible impact of the DR on the voltage imbalance and recommend measures for keeping this power quality parameter within standard limits. For instance, it may require absorbing reactive power, when the active power is generated.

Changing the single phase DR vars and possibly watts for volt/var control may need to be tempered if this significantly impacts the ground current protection.

Addressing reverse power flowMany feeders have the capability to be reconfigured, and this may change the direction of normal power flow through a regulator. For example, if the normal source of supply upstream of a regulator is opened and an alternate feedpoint is closed on the other side of the regulator, then what was the source side of the regulator is now the load side, and the previous load side is now the source side. It is essential that the regulator should regulate the side opposite the side connected to the source of system short-circuit strength. As a convenient means to switch regulated sides in the event of a reconfiguration, without dependence on communications, many regulators have a feature that selects the regulated side as the side from which real power flows away from the regulator. This function presumes that the source of real power is also the source of short-circuit strength.

This is an appropriate assumption, except when DR causes a power flow reversal.

If the reverse power flow is caused not by a change of the EPS supply side, but by an injection of power by DRs on the load side of a regulator, exceeding the load demand on that side, the line regulators and LTC controllers with the reverse power flow logic would switch regulated sides. In general, however, the DR provide much less system strength (short-circuit contribution) than the area EPS. If a regulator reverses sensing in response to a DR-caused power flow reversal, the regulator will become monotonically unstable and drive the tap setting to the upper or lower limit, causing excessively high or low voltages. Thus, for DR-caused power flow reversal, the regulator controls should not switch to the reverse mode of operations.

A possibility for remote (or automatic) enabling of the reverse mode of voltage regulators, when the feeder is reconnected to another feeding bus, should be considered [5], or the reverse flow sensing can be substituted with DMS logic that specifies the regulated side based on the known topology of the system.

If the reverse power flow results in overvoltage due to DR generation exceeding the load, and this overvoltage cannot be mitigated by other volt/var controlling devices, including the DR reactive power control, curtailment of real power of the DR should be considered.

4.1.1.4. Other recommended practices for interconnection studiesIn order to more comprehensively assess the added benefits in the cases of positive DR impacts and the needs and costs of compensating measures in the cases of adverse impacts, the interconnection studies should take into account the impacts of DR operations on:

voltage regulation tolerances

operational parameters of EPS

practically possible objectives of the EPS voltage regulation


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operations of EPS voltage-controlling devices

The extent of involvement of DR in the considerations of the EPS voltage regulation issues, comprising requested information support from DR, modes and setups of volt/var control, as well as communication methodologies, depends on the EPS-specific criteria, which may be based on the expected impact of DR (or group of DR) on the EPS voltage regulation.

If a direct communication between the EPS and a large DR is used for the purpose of central control, and the central control is lost, the DR volt/var controller should be able to recognize the loss of the central control and switch to a default setup [6], which can be also determined by the area EPS.

The Advanced Metering Infrastructure could be used for validation of the execution of the requests issued by the central control to the DR controllers.

4.1.1.5. Bibliography for the Voltage Regulation clause1. IEEE P1547-2003: IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems2. P1547.2TM-2008: IEEE Application Guide for IEEE Std 1547™, IEEE Standard for Interconnecting

Distributed Resources with Electric Power Systems3. Nokhum Markushevich, “Mitigating Voltage Fluctuation Caused by Variability of Distributed Energy

Resources,” Available: http://www.energypulse.net/centers/article/article_display.cfm?a_id=26024. Reigh Walling and Gao, Zhi, “Eliminating voltage variation due to distribution-connected renewable

generation,” DistribuTech 2010.5. F. Katiraei, “Analysis of Voltage Regulation Problem for a 25-kV Distribution Network with Distributed

Generation,” in Proc. of IEEE PES 2006 General Meeting, Jul 20066. Charles J. Jensen, James C. Clemmer, and Nokhum S. Markushevich, “Distribution Automation Pilot

Projects At JEA and OG&E. New Ideas for Remote Voltage and Var Control,” DA/DSM Distributech Conference, January 1999

4.1.2. Integration with area EPS grounding

Recommended Practice – Temporary Overvoltage ControlStd. 1547 clause 4.1.2 requires that DR not produce damaging overvoltages on the area EPS. These are often called temporary overvoltages (TOV) and typically occur when DR backfeeds a ground fault on the area EPS.

The following methods are recommended to meet TOV limits for a ground fault on the area EPS:

Use an interconnection transformer that provides a ground source, accounting also for the DR grounding connection. This method can only be applied if the transformer ground fault current contribution does not disrupt ground fault coordination on the area EPS, which is prohibited in clause 4.1.2.

Use a grounding transformer on the circuit at each DR installation, or one grounding transformer strategically located to suppress TOV for multiple DR installations. . This method can only be applied when it does not disrupt ground fault coordination on the area EPS.

Use an overvoltage trip function that will disconnect the DR before TOV limits are exceeded.

Use a high-speed grounding switch that closes upon fault detection, thereby suppressing TOV until all sources disconnect. Drawbacks of the grounding switch include higher fault currents, arc flash hazards, transient torques on rotating machines, contact welding, and electromechanical reliability.


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Use permissive transfer trip, such that the feeder breaker does not open until all DR sources have been disconnected, so that the circuit is always effectively grounded. The possible increases in fault damage and arc flash hazard should be checked before adopting this method. As with direct transfer trip, this method should also be implemented on pole-top reclosers and alternate feeder sources.

Maintain a sufficient ratio of minimum grounded-wye-connected load to generation such that TOV is not excessive. Only phase-to-neutral connected loads, connected using a grounded-wye to grounded-wye transformer should be considered. The ratio of load to DR depends on the DR characteristics and allowable TOV, but a 3-to-1 ratio of load to DR is typically sufficient.

All of the listed methods should consider coordination between multiple switching and fault-clearing devices, the possibility of alternate feeds during contingency conditions, and the possibility of transmission system events that create unintended islands.

Normally, surge arresters in the area EPS are the first-to-fail during high TOV events. Customer equipment connected through grounded-wye transformers is also subject to the TOV. However, the TOV withstand limits of customer equipment are largely undefined. TOV limits should not be increased by upsizing surge arresters in the area EPS, because that may leave customer equipment vulnerable to the un-mitigated TOV.

The isolation of a portion of the Area EPS, presenting the potential for an unintended DR island, is a special concern and is addressed in 4.4.1.

Setting adjustments may only be made as approved by the authority that has jurisdiction over the DR interconnection.

4.1.3. SynchronizationNo changes were recommended for expanded use of DR.

4.1.4. Distributed resources on distribution secondary grid and spot networks The recommendation is to not connect DR between 10-20 MVA to distribution secondary grid or spot networks. No other changes were recommended for expanded use of DR.

4.1.5. Inadvertent energization of the area EPSThe DR shall not energize the Area EPS when the Area EPS is de-energized unless under agreement with the Area EPS operator. Guidance for intentional islanding can be found in IEEE Std 1547.4.

4.1.6. Monitoring provisionsNote: This section will be supplemented by the information in Clause 6.

4.1.7. Isolation deviceNo further requirements or changes are recommended for expanded use of DR.The Isolation Device may be electrically located anywhere between the point of common coupling and the generator. However, the customer should consider the impact of the electrical location of the Isolation Device. If the Isolation Device is electrically located at or near the generator, and the Area EPS Operator uses the Isolation Device to provide clearance for worker safety, the customer will be unable to operate their generator to maintain electric supply to all or a portion of their load on the Local EPS during an outage of the Area EPS.

Operation of this Isolation Device must be restricted to the Area EPS Operator’s personnel and properly trained operators designated by the Customer. Designated Customer personnel may be required to learn and adhere to the Area EPS Operator’s ―Switching and Tagging‖ procedures.

4.1.8. Interconnect integrity


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4.1.8.1. Protection from electromagnetic interferenceNo further requirements for expanded use of DR. Considerations for testing are given in 5.1.3.1.

4.1.8.2. Surge withstand performance No further requirements for expanded use of DR. Considerations for testing are given in 5.1.3.2.

4.1.8.3. Paralleling deviceNo further recommendations made.

4.2. Response to area EPS abnormal conditions No recommendations made.

4.2.1. Area EPS faultsRecommended Practice – Detecting Area EPS FaultsStd. 1547 clause 4.2.1 requires that DR de-energize the area EPS during faults on the connected circuit. This may be difficult during high-impedance ground faults, or any fault that produces negligible impact on the DR voltage and/or current. However, the goal should be to detect and clear any fault that the area EPS detects, and furthermore, not to impair the area EPS ability to detect faults, particularly ground faults.

Historically, the detection of high impedance ground faults has been an unresolved issue. The Area EPS protection will not be able to detect all ground faults. Therefore, it is not reasonable to make detection of all ground faults a requirement for DR protection. An evaluation should be made of the maximum ground fault impedance that the area EPS will detect, with and without DR, and compare that to the area EPS design level of ground fault impedance. If the area EPS can no longer detect ground faults with DR contributions, then ground fault contributions from the DR should be limited (e.g. by adding neutral impedance to the interconnection transformer), or the area EPS protection schemes should be changed to work with DR.

Any scheme to disconnect the DR from a faulted EPS must consider the following factors: The interconnection breaker shall be able to interrupt faults in both directions.

If the DR has automatic reconnection, it shall not reconnect when the fault occurred on its side of the point of interconnection.

A method to prevent inadvertent tripping of the substation circuit breaker for the circuit with DR, during faults on an adjacent circuit.

Any desensitization of the Area EPS relays due to fault contribution from the DR shall still result in acceptable fault clearing behavior. This is particularly critical for ground faults. Desensitization for ground faults may be addressed through the use of impedances connected in the DR interconnection transformer neutral, using high impedance grounding of the DR, or the use of a delta winding. However, depending on the transformer connection, adding impedance in the transformer neutral will increase temporary overvoltage (TOV) during ground faults. TOV is reduced by reducing the neutral or zero sequence impedance. Therefore, minimizing both TOV and desensitization are competing objectives. Refer to Annex G titled Temporary Over –Voltages on Distribution Systems Associated with the Connection of Distributed Generation.

DR protection shall coordinate with line recloser operation to prevent formation of an island due to backfeeding of an Area EPS fault by the DR through a line recloser.


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DR fault clearing times must coordinate with any fast reclosing scheme in use by the Area EPS to prevent adverse consequences to the Area EPS, the DR, or other customers.

Fault detection and clearing times of single-phase DR must be acceptable for faults on any Area EPS phase, when the fault is located within the DR zone of protection looking into the Area EPS.

The effect of reverse fault current flow from DR at the distribution level on subtransmission relays such as distance relays should be evaluated. This is a direct effect of high or very penetration levels of DR, and will be impacted by the type of DR. For example, inverter based DR may have little or no impact, while induction or synchronous DR may have a significant impact.

The DR owner, regardless of technology employed, should provide the Area EPS with the maximum instantaneous value of fault current contribution from the DR for both single-line-to-ground and phase-to-phase faults for these time periods:

Time 0 to 1 cycles (including asymmetry) (used for evaluating DR impact on close-and-latch (sometimes called momentary or first-cycle) ratings of switchgear on the Area EPS).

Time 1 to 4 cycles (used for evaluating DR impact on equipment overcurrent withstand ratings on the Area EPS).

Time 4 to 30 cycles (used for evaluating DR impact on switchgear and fuse interrupting ratings on the Area EPS).

Time 30 cycles and beyond (used for evaluating DR impact on timed protection on the Area EPS).

Any of these fault contributions may be reported as zero when appropriate. Either per-unit or ampere values may be reported. The DR owner should also provide the impedances and winding connections of any interconnection transformers used between the DR and PCC.

The area EPS operator’s use of any of the fault detection options listed below needs to balance equipment safety and system reliability with specific DR technology, interconnection transformer, EPS and DR protection practices, and Area EPS operating practices. Synchronous generators may use distance (impedance) relays, voltage-controlled overcurrent relays, or voltage-

restrained overcurrent relays as described in Std. 1547.2. Zone settings may become complicated with multiple DR sources.

Induction machines may use overvoltage, undervoltage and overcurrent relays. It may be appropriate to treat these like synchronous machines, if there is an available excitation source.

Inverters, which contribute little fault current2, may use voltage and frequency trip settings in conjunction with an active anti-islanding detection method, or other dedicated fault detection technique. Refer to clause 4.4 for active island detection method descriptions.

Voltage trip settings may be used without active anti-islanding detection, if a detectible voltage excursion occurs for all fault types and locations on the area EPS. This evaluation should account for the interconnection transformer winding connections and the voltage transformer (VT) location.

2 Details of inverter fault behavior are specific to the inverter design and controls, in contrast to the fault behavior of rotating machines, which can be predicted from basic physics. As a practical limit inverter fault current sub-cycle injections can reach 2.2 per-unit, and typically decrease rapidly over time to 1.2 – 1.4 per-unit until the inverter disconnects or the fault clears. Sub-cycle transients from discharging filter capacitors may increase the fault current injection.

citation: Investigation of Solar PV Inverters Current Contributions during Faults on Distribution and Transmission Systems Interruption Capacity, Katiraei, Holbach et al., WPRC, October 2012


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Zero sequence voltage trip (aka ground voltage or residual voltage trip) may be used to detect ground faults on the area EPS. Considering the interconnection transformer ability to pass zero-sequence voltage and the configuration of the area EPS, it may be necessary to install VTs on the high side.

Zero sequence current trip may be used to detect ground faults on the area EPS. This can be implemented with a CT in the grounded neutral of an interconnection transformer or grounding transformer, when one exists.

Sequential trip may be deliberately incorporated into the detection scheme, and should also be considered for possible adverse impacts. For example, if an area EPS device trips first, that may change the system from effectively grounded to ungrounded. That change could allow zero sequence voltage tripping to work for DR, but may also interfere with other detection methods and lead to high overvoltage. Trip sequences affect the time settings for both Area EPS and Local EPS devices.

Direct transfer trip may be used to disconnect the DR after an area EPS device detects the fault.

Protection Options SummaryThe protection options for connecting DR to the Area EPS should have the following attributes:

The DR protection shall be able to detect faults on the Area EPS with all levels of generation from minimum to maximum and de-energize the circuit to which it is connected.

The DR protection shall de-energize the circuit to which is connected prior to the Area EPS reclosing. The DR should not prevent the Area EPS from detecting faults. Address both the Area EPS and DR interconnection requirements. Be adaptable and flexible as practical to changes in circuit characteristics and penetration level. For

example, scalable from one option to the next and to future expansions of DR size and type. The protection solution for the DR connection shall be consistent with existing power system reliability

requirements.

The protection options described herein are suitable for both three wire and four wire distribution systems. Option 1 is the least complex with complexity increasing with higher numbered options. The five options cover the range from low penetration to high penetration and from small DRs to large DRs. To select the most appropriate option, one would begin with the least complex option, perform a fault and coordination study, establish settings, and then determine if proper protection coordination can be achieved. If not, to move up to next level of complexity.

The option finally selected should address all protection issues uncovered by the fault and coordination study. These include but are not limited to:

Prevention of false tripping of healthy feeders with the addition of the DR for faults on adjacent feeders.

Prevention of unacceptable levels of blinding or desensitizing the existing protections when the DR feeds fault current into a local fault.

Prevention of unintended islanding, through tripping of a feeder recloser or main circuit breaker, which can lead to blocking of auto reclosing, an unsynchronized reclose or removal of ground sources.

Ensuring proper protection at the PCC such that the interconnection protection is selective for both faults on the area EPS and faults within the DR site.

Options 1A through 2B can be implemented on reclosers between the substation and DR site. Options 3 through 5 may be suited for substations only; see Annex F for more details.

The DR characteristics and interconnection technology does have an impact on the performance of a various fault detection techniques. For example, the fault current and voltage at the PCC for a particular fault on the distribution will be quite different when the DR is inverter based than it would for a traditional synchronous generator based DR.

Table # - Example protection options

Option Area EPS (Utility) Protection

DR Protection Comments

1A Overcurrent Traditional anti-islanding consisting of under and over

No upgrades required at the utility. Penetration limited to


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voltage, under and over frequency.

50% of minimum measured load.

1B Overcurrent Enhanced anti-islanding consisting of consisting of under and over voltage, under and over frequency, plus rate-of-change of frequency, and/or vector shift and/or reactive power shift. For inverter based DR, voltage supervised overcurrent is used to address the current limiting response of inverters.

No upgrades required at the utility. The additional anti-islanding functions, some of which are found in modern inverters, provide a higher degree of certainty that the DR will trip. As a result, some jurisdictions will allow a higher level of penetration.

2A Overcurrent Enhanced anti islanding protection as in 1B above plus line protection. Line protection designed to detect all faults on the distribution feeder consisting of directional overcurrent, negative and zero sequence over current and over voltage, under and over voltage set to operate on fault inception. For inverter based DR, voltage supervised overcurrent is used to address the current limiting response of inverters.

No upgrades required at the utility. The DR trips on fault inception and does not wait for the island to form. Provides a much higher degree of certainty that DR will trip when compared to 1A and 1B. Requires a study to apply.

2B Overcurrent plus voltage supervised reclosing.

Same as 2A. Upgrades required at Area EPS. Same as 2A but the addition of voltage supervised reclosing at the substation eliminates the risk of an out-of-phase reclose and enables the feeder to accept any type of DR with no penetration limit.

3A Overcurrent plus auto-ground. Auto ground consists of a circuit breaker that applies a three phase fault on the line side of the feeder circuit breaker after it opens.

Same as 2A. Upgrades required at Area EPS. Enables the feeder to accept any type of DR with no penetration limit. The application of a three phase fault will ensure the DR disconnects in a timely manner.

3B Overcurrent plus voltage supervised reclosing and an auto-ground.

Same as 2A. Slightly more complex than 3A. Enables the feeder to accept any type of DR with no penetration limit. The voltage supervised reclosing further reduces the risk and only requires the application of the three phase fault when one or more DRs fail to disconnect.

Option Area EPS (Utility) DR Protection Comments


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Protection3C Overcurrent plus voltage

supervised reclosing and slow transfer trip, <0.5 seconds. .

Same as 2A plus slow transfer trip receive.

DR must be able to receive the trip signal. Requires a transmitter at the utility to broadcast a signal to trip all DR on the feeder when a fault occurs.

4A Distance or directional overcurrent, voltage supervised reclosing,

Same as 2A but directional overcurrent may be replaced with distance relaying.

More complex than any of the options above. Required when there are multiple line sections on the feeder. Enables the line section to accept DR without a penetration limit.

4B Distance or directional overcurrent, voltage supervised reclosing plus auto-ground.

Same as 4A. The addition of the auto-ground ensures disconnection of the DR. Enables the line section to accept any type of DR without a penetration limit.

4C Distance or directional overcurrent, voltage supervised reclosing plus slow transfer trip.

Same as 4B plus slow transfer trip

The addition of the slow transfer trip ensures disconnection of the DR. Enables the line section to accept any type of DR without a penetration limit.

5 Distance, or directional overcurrent, or line current differential plus teleprotection.

Distance, or directional overcurrent, or line current differential plus teleprotection.

Very complex. Requires high speed communication channels for the tele-protection and is only necessary for large DRs and/or very high levels of penetration. This option is typically applied on the sub-transmission or transmission system and rarely applied on the distribution system. Enables the line section to accept any type of DR without a penetration limit

Note: Refer to Annex F for more details on the options described above.

4.2.2. Area EPS reclosing coordination

Recommended Practice – Reclosing CoordinationStd. 1547 clause 4.2.2 requires that DR cease to energize the area EPS before any reclosing operation by the area EPS. The following methods are among those recommended to meet this requirement: Lengthen the area EPS reclosing time beyond 2 seconds, or beyond the maximum time allowed for DR to detect

and de-energize an island, if this is acceptable to the Area EPS operator. Shorten the DR clearing time (i.e. cease-to-energize time) below 2 seconds, so that the Area EPS can also use a

reclosing time shorter than 2 seconds, if this is acceptable to the Area EPS operator. Area EPS reclosing can leave the circuit de-energized for a period as short as 16 cycles. This imposes a more stringent requirement on the DR than Std. 1547 clause 4.4.1, but it could result in better power quality within the area EPS.

Use voltage-supervised reclosing at the Area EPS device to permit reclosing only when there is typically 20% or less voltage on the load (island) side, such that rotating machines can be re-energized without damage. This


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may allow faster reclosing times without imposing more stringent requirements on the DR. For three-phase DR, all three phases will need this protection.

DR including inverters may continue to energize rotating machines, including motors, which could be damaged upon Area EPS reclose. Out-of-phase reclosing can result in a number of severe consequences. Rotating generators can be subjected to extreme torques. Also, motors connected to the Area EPS and their mechanical loads can be subjected to extreme torques. Severe transient overvoltages can also result, particularly if the Area EPS includes capacitor banks or large sections of underground cable. Communication-based island detection should be considered for DR in these cases.

DR operation and protection shall be fully coordinated with the Area EPS under an agreement with the Area EPS operator.

In accordance with Section 4.2.2 Area EPS reclosing coordination, a 2-second response time may not be adequate to coordinate with the Area EPS reclosing practices. This may result in damage to the generator upon reclosing of the EPS source. In some instances, on a case-by-case basis, the EPS operator may allow the reclosing time to be increased or add synchronism check supervision to provide coordination. Increasing the reclosing time in some cases will have an unreasonable impact on other customers. Other means, such as transfer trip or dead-line checking, can be used to insure isolation of the generator before automatic circuit reclose.

4.2.3. Voltage

The Area EPS should consider voltage trip settings that allow DR to ride through faults on adjacent circuits or the transmission system. Table 1 shows a range of voltage trip settings that provide more voltage ride-through capability than the defaults in IEEE 1547. The voltage range applies independently to each of the monitored phase-to-phase or phase-to-neutral voltages, depending on the type of interconnection transformer. Both minimum and maximum clearing times should be considered. Transient stability studies may be used to help determine these times. These times should coordinate with Area EPS reclosing practices.

The ranges in Table 1 permit low-voltage ride-through (LVRT) under mutual agreement between the Area EPS and DR operators. LVRT capability means that during periods of low voltage, the DR does not cease to energize the Area EPS, except to comply with clauses 4.2.1, 4.2.2 and 4.4.1 of IEEE 1547, and in consideration of the DR operating capabilities. The operating parameters should be specified when this LVRT function is provided. Clearing time is the time between the start of the abnormal condition and the DR ceasing to energize the Area EPS. The ride-through time is equivalent to relaying time, and the clearing time is equivalent to relaying time plus breaker time. Therefore, ride-through time will be less than the clearing time. For example, to achieve a 0.16-second ride-through time with 100-ms breakers, the clearing time would be at least 0.26 seconds.

Table 1 Interconnection system default response to abnormal voltages

Default settingsa

Voltage range (% of base voltageb) Clearing time (s)

Clearing time: adjustable up to and including (s)

V < 45 0.160.16

45 ≤ V < 60 1 1160 ≤ V < 88 2 21

110 < V < 120 1 13V ≥ 120 0.16 0.16


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a Under mutual agreement between the EPS and DR operators, other static or dynamic voltage and clearing time trip settings shall be permittedb Base voltages are the nominal system voltages stated in ANSI C84.1-2011, Table 1.

The Area EPS may consider dynamic response of DR to long-term abnormal voltages that occur without nearby faults. For example, if any monitored voltage drops below 88%, the DR may switch from its normal operating mode to inject reactive power. When the voltage increases above 88%, the DR may revert to its normal operating mode. This application would require a dynamic study of DR operation during disturbances in order to design the DR response. Deeper voltage drops (e.g. below 45%) may still cause the DR to disconnect, or to disable this grid support function. See Annex H for more details and background on voltage ride-through.

4.2.4. Frequency

The DR response to frequency deviation shall be established in coordination with the Area EPS. DR is not required to operate at frequencies below 56 Hz. Reset logic should be based on the product of frequency times duration of the deviation.

For systems that may experience larger frequency swings on single contingencies, the Area EPS operator should specify appropriate frequency settings to prevent unnecessary loss of generating resources. Table 2 shows a range of frequency trip settings that are more compatible with ride-through than the default frequency trip settings in IEEE 1547. Breakpoints for UF1 and UF2 are adjustable from 56 to 60 Hz, and breakpoints for OF1 and OF2 are adjustable from 60 to 64 Hz. These would apply to any size of inverter DR, which may require field-adjustable but tamper-proof settings. Clearing times include both relay and breaker times.

The ranges in Table 2 permit low-frequency ride-through (LFRT) under mutual agreement between the Area EPS and DR operators. LFRT capability means that during periods of low frequency, the DR does not cease to energize the Area EPS, except to comply with clauses 4.2.1, 4.2.2 and 4.4.1 of IEEE 1547, and in consideration of the DR operating capabilities. The operating parameters should be specified when this LFRT function is provided. Clearing time is the time between the start of the abnormal condition and the DR ceasing to energize the Area EPS. The ride-through time is equivalent to relaying time, and the clearing time is equivalent to relaying time plus breaker time. Therefore, ride-through time will be less than the clearing time. For example, to achieve a 0.16-second ride-through time with 100-ms breakers, the clearing time would be at least 0.26 seconds.

Table 2—Interconnection system default response to abnormal frequencies

Default settings Ranges of adjustability

Function Frequency (Hz)

Clearing time (s)

Frequency (Hz)

Clearing time (s) adjustable up to

and includingUF1 57 0.16 56 – 60 10UF2 59.5 2 56 – 60 300OF1 60.5 2 60 – 64 300OF2 62 0.16 60 – 64 10

The Area EPS operator should also consider specifying a dynamic DR output response to frequency deviations, which may assist in maintaining system stability. For example, DR output reduction of 40% of nameplate power per Hertz above 60.5 could be specified, until the frequency exceeds 63 Hertz, at which point the DR could trip and clear within up to 300 seconds. This function would use OF1 frequency setpoint adjustments that are allowed in Table 2. For DR capable of increasing output, including storage-based DR, a similar dynamic response to under-frequency conditions should also be considered. These are steady-state droop characteristics; DR will respond to


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frequency deviations in different time frames depending on the technology. See Annex H for more details and background on frequency ride-through.

4.2.5. Loss of synchronismNo recommendations made.

4.2.6. Reconnection to area EPS DR reconnection shall only take place when the Area EPS voltage is within Range B of ANSI C84.1-1995, Table 1, and frequency is within a range of 59.3 Hz to 60.5 Hz, or other bounds established by the Area EPS The DR interconnection system shall include an adjustable delay (or a fixed delay of five minutes) that may delay reconnection for up to five minutes after the Area EPS steady-state voltage and frequency are restored to the ranges identified above.

If there are multiple DR units of significant size connected to the Area EPS, a staggered or softened reconnection scheme should be considered. This will reduce the perceptible voltage fluctuation as each DR reconnects one at a time, rather than all at once. Staggered reconnection can be implemented with fixed delay, plus adjustable and randomized delays on each DR unit. Inverter-coupled generation could also ramp linearly to full power over an adjustable or fixed five-minute period to soften the reconnection.

For larger generating units, an Area EPS may require verbal communication with the System Operator before returning generation to the system.

If the DR can support an out of range area EPS and help bring the Area EPS back to normal condition, a DR can connect on command from the area EPS operator.

4.3.Power Quality

4.3.1. Limitation of DC injectionNo recommendations made.

4.3.2. Limitation of flicker induced by the DRNo recommendations made.

4.3.3. HarmonicsIn addition to the IEEE 1547 Harmonics requirement (i.e., each DG installation must, at its PCC, meet the injected harmonic current distortion limits provided in IEEE 1547 Table 3 [excerpt IEEE 519 Table 10.3]) when multiple DG units are operating at different PCCs, each alone may meet the preceding current injection limit; however, the aggregate impact of all the DG units could still cause voltage distortion that would adversely impact other non-DG customers.

Therefore, the aggregate voltage distortion at EACH PCC must also not exceed IEEE 519 limits. Studies should be performed to determine if excessive harmonic distortion will occur prior to installation of the DG. However, it may not be possible to predict the net level of voltage distortion before each new DG installation on a given circuit. Voltage distortion in excess of IEEE 519 can be used as a benchmark to trigger corrective action (including disconnection of DG units) if service interference exists.

4.4. Islanding4.4.1. Unintentional islanding


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The island or fault detection times should be coordinated with Area EPS reclosing practice, which can leave the circuit de-energized for a period as short as 16 cycles.

Recommended Practice – Detecting Unintended IslandsStd. 1547 clause 4.4.1 requires DR to detect unintended islands and de-energize the area EPS within 2 seconds. The following methods are recommended to detect and de-energize islands:

1. Aggregate DR capacity on the smallest switched (or fused) connected circuit segment of the area EPS is inherently no more than 1/3 of the minimum time-coincident load (e.g. minimum daytime load for PV) on that connected circuit segment. This method requires load measurement or survey data, rather than a test, for verification. The criterion was originally based on tests and simulations of self-excited induction generators connected to feeders with shunt capacitor banks, including effects of ferroresonance and the possibility of dynamic overvoltage. Similar criteria may apply to inverters, synchronous machines, and other DR technologies if based on documented tests. In effect, these criteria amount to a waiver of islanding detection whenever adverse consequences can be ruled out. There is a risk that future DR growth could invalidate the “waiver” for existing DR.

2. DRs with an aggregated capacity greater than the 1/3 minimum load may be capable of dynamically limiting output to 1/3 of current load on the circuit segment, either through monitoring of appropriate values or through operator command to limit output. In this way, such DR can implement method 1.

3. Voltage and frequency trip functions are provided that coordinate with the area EPS and work in conjunction with one of the following methods:

a. Active island destabilization with positive feedback (e.g. perturb and observe) scheme. This method can pass the UL-1741 test for perfectly matched load and generation.

b. Governor and excitation controls that maintain constant power and power factor. When islanded with a load that doesn’t match the set power and power factor, voltage and frequency excursions may be used to trip the generator. This method would not pass the UL-1741 test if the power and power factor match.

c. Induction generators that will be under-excited in the island, accounting for all feasible levels of shunt capacitor banks that might be connected in both the local and area EPS.

Method A requires a test to verify that islands with perfectly balanced load and generation are de-energized within 2 seconds, as detailed in Std. 1547.1. Methods B and C rely on the unlikelihood of perfect power balance, and also on the fact that a rotating machine should not generate damaging voltage or frequency excursions when the real and reactive power levels are perfectly balanced. Neither B nor C guarantees detection within 2 seconds.

4. Reverse power flow relays are provided for DR units that will not export power to the area EPS through the PCC. Minimum import tripping is a variant of this method. If this method is not sensitive enough, or if nuisance trips occur, then another method should be considered.

5. Direct transfer trip is used to disconnect the DR within 2 seconds after any upstream area EPS interrupter or switch opens to create the island. This method should not be used if a melted fuse in the area EPS might create the island. Redundant communication channels should be provided, unless the scheme operates in a permissive connection mode.

6. Other methods have been proposed from research, such as phasor monitoring, signal processing of harmonics, and insertion of a low-frequency signal by the utility on power line carrier (PLC). Before adopting such methods:


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a. In developmental field trials, provide a well-established islanding detection method as backup.

b. Consider variations in circuit load, configuration, and frequency response to develop setting procedures for both Area EPS and Local EPS operators.

c. Develop a commissioning test plan that will verify proper operation.7. For DR with effective fault and overvoltage detection, the allowable island run-on time may

be lengthened beyond 2 seconds, in coordination with the Area EPS and its reclosing practices.

Many of these methods could have a non-detection zone (NDZ), especially with multiple DR installations on the area EPS. Situations like that may call for detailed modeling, testing, monitoring, or other systems engineering.

Where primary anti-islanding schemes may fail for low probability cases of close load and generation match, the addition of a slower backup transfer trip using technology such as cellular type radio may be considered. This would be SCADA quality communications with 1-2 seconds response instead of Transfer Trip quality communications that respond in 50-100 milliseconds.

4.4.2. Intentional islandingSee IEEE Std 1547.4-2011.

5. Interconnection test specifications and requirementsSome of the expanded-use functions presented in Clause 4 and other parts of this document are already being considered in the amendments IEEE P1547 and IEEE P1547.1a. This clause describes some of the general considerations and specific requirements of testing expanded-use functions. Primarily, these consist of new voltage regulation functions, advanced islanding detection and fault detection techniques, temporary overvoltage control, and ride-through capabilities.

In developing new tests, the procedures should consider communications and information exchange, micro-grid applications, and scenarios with multiple DR interface technologies. Any new test procedures should also ensure that the fundamental safety requirements of unintended islanding detection, fault detection and overvoltage limits are still met. More complicated expanded-use applications are likely to require more detailed impact studies, and this may be considered in developing new test procedures.

5.1.New voltage regulation testsIn order to meet the expanded-use voltage regulation requirements defined in Clause 4.1.1 of this document, the following interconnection test requirements should be considered for prospective DR systems:

Ability to generate and absorb reactive power

Ability to control real power

Ability to locally (autonomously) control the DR real and/or reactive power following one or more of these modes of control, within the DR capability limits:

o Constant reactive power, without or with voltage override, within given ranges of voltage setpoints, time delays, modes of control (PID) and other setpoints..

o Constant power factor, without or with voltage override, within given ranges of voltage setpoints, time delays, modes of control (PID) and other setpoints


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Constant voltage setpoint attributed to a given (observable or fictional) bus, within given ranges of voltage setpoints, bandwidths, time delays, and modes of control (PID). Ability to preset the modes of operations and their setpoints by a schedule downloaded to the controller either locally, or remotely

Ability to update the modes of operation and their setpoints remotely in the near-real time

Ability to recognize the loss of the central control, if used, and to switch to a default setup.

All tests mentioned in sub-clause 5.1 along with the Anti-islanding protection tests should consider the possibility of multiple DR.

The ability to meet these requirements should be tested on a representative model of an EPS either in the factory, in a testing laboratory, or on the equipment in the field during commissioning. The results of these tests should be consistent with the DR settings and P-Q-V capability limits, within specified tolerances. The expected range of EPS circuit impedance, both magnitude and angle, should be specified and tested.

5.2.EMI TestThis refers to Clause 5.1.3.1 of IEEE 1547. Large DR units cannot be placed in a turn-table and be rotated to apply EMI from all directions. Sometimes the setup would not allow rotation, or it may otherwise be impractical. In that case, EMI may be applied only in directions that may affect the unit, and the location of the antenna may be selected according to the location of control boards and other susceptible components.

5.3.New short circuit behavior testThe DR interface unit, regardless of technology employed, should be type-tested to determine the maximum instantaneous value of fault current contribution for three-phase-to-ground, single-phase-to-ground and phase-to-phase faults for these time periods:

• Time 0 to 1 cycles for close and latch consideration.• Time 1 to 4 cycles for equipment withstand.• Time 4 to 30 cycles for interrupt ratings.• Time 30 cycles and beyond for backup protection analysis.

The reported current maximums should encompass any fault initiation point-on-wave effects and any asymmetries among phases. Test results may be reported in per-unit or amperes, and zero values may be reported as appropriate.

The test should be performed with all anti-islanding, control, and protection systems operating as intended for installation. Behavior during other operation modes should also be reported, as it may influence area EPS requirements for backup protection. The test report should document the interconnection transformer included, if any, along with any requirements on the interconnection transformer for the test results to be valid. The DR owner and the area EPS may use this information to adjust interconnection transformer specifications.

5.4.New loss of load behavior testInverter-based DR should be type-tested to determine the overvoltage that occurs at the inverter terminals upon sudden loss of rated load. The tested DR output should be 100% of rated current before disconnection, and zero after disconnection. The test should be performed with all anti-islanding, control, and protection systems operating as intended for installation. The test report should document the interconnection transformer included, if any, along with any requirements on the interconnection transformer for the test results to be valid. The resulting overvoltage should not exceed 200% (TBD) of nominal during the first cycle, or 139% of nominal sustained. The maximum RMS voltage values 1 cycle and 10 cycles after disconnection should be reported.

6. Monitoring, Information Exchange, and Control (MIC)


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6.1.Communications for DR FunctionsFor high penetrations of the DR into the EPS, communications for information exchanges between DR systems and the EPS operator become increasingly important, depending upon the EPS environment and the size and/or number of the DR systems. In particular,

DR systems are becoming “smart” and capable of performing many advanced functions that may improve EPS reliability and efficiency. Annex K contains descriptions of many of these advanced DR functions, including their communication requirements.

Most of these DR functions can operate “autonomously” based on pre-established settings that are implemented during the installation of the DR system or that may be updated occasionally. These settings are used by the DR systems to respond to local conditions (e.g. voltage levels and frequency) to counter anomalous situations. For instance DR systems may use volt-var settings to counter voltage levels that are trending either too high or too low, or may modify their power output to counter frequency increases or decreases. Although these DR functions do not rely on real-time communications, many can be enhanced by communications in which the autonomous settings can be modified, scheduled, or overridden during system abnormal conditions.

Communications may also be important for the EPS operators to monitor the state of the DR output and capacity in real-time, while emergency commands may be critical for managing some larger DR systems or groups of smaller DR systems. Although DR systems will usually operate autonomously, communications are necessary for real-time monitoring and control, particularly during emergency situations, while updates and maintenance actions can be undertaken more efficiently and in a timely manner through communications. Some communications may use traditional point-to-point communication channels, while others may utilize broadcast or multicast communications, such as is possible through broadcast cellular technology.

Commercial and industrial DR systems will often be managed by an energy management system within a facility, while residential DR systems may be managed by third party aggregators or retail energy providers, or not at all. Therefore, communications between Area EPS operators and DR systems may be indirect, or non-existent.

Small DR penetrations in strong or stiff Area EPS locations generally do not require direct communications with the EPS operator, while large DR penetrations in weak Area EPS locations may require very complex communication interactions in order to maintain EPS stability and reliability, in particular to coordinate their autonomous actions with EPS distribution automation actions. Aggregations of even the smaller DR systems can improve the reliability and efficiency of the EPS, just by their sheer numbers.

6.2. Communication Technologies for DR SystemsCommunications technologies are layered: typically categorized in the following 4 layers:

Abstract information model that defines the types of data that can be exchanged, but does not specify the actual “bits-and-bytes” protocols. The international standard information model for DR systems is IEC 61850-7-420 with the advanced functions described in IEC/TR 61850-90-7. It defines the information model for the data exchanges needed for most of the DR functions listed in Annex K. It is expected to be used for most information exchanges between DR systems and other systems.

Application layer protocols that define the “bits-and-bytes” for “mapping” the abstract information model data into protocol formats. Typical application layer protocols include DNP3, ModBus, MMS, HTML, and various XML-based protocols. Currently most DR manufacturers rely on ModBus for their local interfaces, but expect ModBus to be translated to other protocols for any wide-area interactions.

Transport layer protocols that provide the means to carry the data from one system to another. The most common protocols are the Internet protocols TCP/IP. For DR systems it is expected that IPv6 will become increasingly used in the future.


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Communication media that defines the physical technology for carrying the protocols. Some communication media are public while others may be privately owned. Typical media include microwave, fiber optic, cellular GPRS, radio-based systems, satellite, and the Internet. The expectation is that any media that supports TCP/IP would be acceptable for interacting with DR systems.

Cyber security must, at a minimum, provide authentication for information exchanges (i.e. both the DR system and the EPS operator are who they say they are and that they are authorized to interact). Additional cyber security can also be used to provide confidentiality (prevent unauthorized access to sensitive information) and non-repudiation (ensure that the information was received and cannot be denied). Audit logs of all significant events provide records of these interactions. Cyber security is addressed in more detail in IEEE 1547.3.

To promote interoperability of implementations of DR systems by different manufacturers and installed in different Area EPS, the use of the IEC 61850 standard as the information model for advanced DR functions is strongly recommended.

6.3. Different Communication Requirements for Different DR ScenariosDifferent stakeholders require different types of information exchanges for managing different DR scenarios. Many of these stakeholders are identified in the IEEE 2030 document, while additional stakeholders are identified in various other reports and papers. Those information exchanges include requirements for updating autonomous settings for the DR functions, market interactions, maintenance, local monitoring and control for managing preferences for DR owners, statistical and historical reporting, as well as direct utility monitoring and control.

In many scenarios, communications will be hierarchical. The utility communication networks will connect with facility energy management systems or with third-party aggregators or energy providers. In turn, these middle systems will then communicate with the DR systems that they are responsible for, sometimes just passing on commands or possibly allocating utility requirements across multiple DR systems or aggregating DR data. This communications hierarchy may not be one-to-one with the power system hierarchy of Area EPS interconnected at the PCC to the Local EPS. For instance, third-party aggregators may manage many different DRs that are spread throughout a utility’s EPS each with its own PCC, or a campus energy management system that manages all DR units as well as loads within its domain.The actual telecommunications media, networks, and protocol standards used for these information exchanges are beyond the scope of this document (but may be addressed in updates to IEEE 1547.3).

As the management of DR systems becomes more dependent on communications, the loss of communications beyond a mutually-defined time window should cause DR systems to go into a previously-defined default state, as determined by the DR owner and the EPS operator.

Table 6-1 provides recommendations on those types of information exchanges that are important for DR interconnections to the Area EPS where many of the DR functions identified in Annex K are required or permitted by the EPS operators (not all DR systems will have or need these capabilities). The columns of this table are described more completely in the following subsections.


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Table 6-1: Categorizations of DR System Recommendations for Monitoring and Control

1. Sensitivity of the EPS environment

2. Relative “size” (impact) of DR system at the PCC

3. Type of communications between EPS operator and DR systems

4. EPS Operator monitoring of real power, reactive power, and voltage at the PCC

5. DR and EPS protection

6. Autonomous DR functions including both energy and ancillary services with settings modifiable via communications

7. EPS operator manages the DR systems through direct monitoring and control and/or through schedules

(A) Less Sensitive Environment (low generation-to-load, strong EPS, small generation or load variability within area)

Small DR and/ or small number of DRs

Autonomous DR operations only: data communications not necessary

Not justifiable Local DR anti-islanding and protection not typically used.

If mutually beneficial to EPS operator and DR owner

Not justifiable

Med DR and/or medium number of smaller DRs

Autonomous DR operations and data

communications broadcast to groups of

DRs, possibly voice

Monitoring for system management

DR protection Option 2



Large DR and/or large number of smaller

Autonomous DR operations with data

communications required directly to DR or DR EMS including coordination of

protection


DR protection Option 2, Option

3, or Option 4

Recommended, with utility-selected autonomous functions

required

If needed for power system stability or mutually beneficial to EPS


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DRs operator and DR owner

(B) More Sensitive Environment (high generation-to-load, weak EPS, large generation or load variability within area)

Small DR and/ or small number of DRs

Autonomous DR operations and data communications broadcast to groups of DRs, possibly voice




Not justifiable

Med DR and/or medium number of smaller DRs

Autonomous DR operations and data communications broadcast to groups of DRs, possibly voice

Recommended if no autonomous emergency and functional modes

DR protection Option 2, Option 3, or Option 4

Recommended, with utility-selected autonomous functions required

If needed for power system stability or mutually beneficial to EPS operator and DR owner

Large DR and/or large number of smaller DRs

Autonomous DR operations and data communications required directly to DR or DR EMS, including coordination of protection

Required if no autonomous emergency and functional modes


Required, with utility-selected autonomous functions required

If needed for power system stability or mutually beneficial to EPS operator and DR owner


IEEE P1547.8™/D6.0 January 2014

6.3.1. Categorization of Information Exchanges by EPS SensitivityThe importance of some DR functions is a combination of the DR’s size, the DR’s capabilities, the surrounding DR systems, and the “sensitivity” of the EPS at the DR location. Although obviously there is a continuum from “more sensitive EPS” to “less sensitive EPS”, sensitivity can be defined as the ratio x/y relating small changes x of some dependent variable to small changes y of some independent or controllable variable y. For power systems with high penetrations of DR, sensitivity may reflect the changes to reactive power by changes in feeder voltage, or changes to energy output by changes in the price of energy, or other similar electrical parameters. This sensitivity would necessitate “what if” studies with different scenarios and may require studies such as those described in IEEE 1547.7 in order to determine into what category an EPS and the DR systems interconnected to it may fall. One of the major advantages of advanced DR systems may be their ability to counter some of these sensitive responses.

Column 1 in Table 6-1 provides guidelines for categorizing the recommended information exchanges by DR size and EPS “sensitivity”, in which small DRs or small groups of DRs (e.g. <100 kW, medium (e.g. 100 kW – 1 MW) and large DRs or large groups of DRs (e.g. > 1 MW) (based on nameplate information) are located within different environments:

A. Low sensitivity environment is characterized by:

Low generation-to-load ratio, such as smaller than 1-to-2 or 1-to-3

Strong or stiff EPS (the EPS at the DR location is very stiff and can handle significant fault current,

Small variability of generation and/or load within area, including due to feeder switching

B. High sensitivity environment is characterized by:

High generation-to-load ratio, such as larger than 1-to-2 or 1-to-3

Weak Area EPS (there is significant impedance between the DR and the EPS source substation)

Large variability of generation and/or load within area

Each EPS operator will determine what the specific power ranges and conditions are applicable for each category. Where DR penetration is evaluated, the EPS operator will also determine which definition of penetration is to be applied for categorization of the system.

6.3.2. Size of Single or Multiple DR systemsColumn 2 in Table 6-1 indicates the size of a single or multiple DR systems. Multiple DR systems could be behind a single PCC, but could also reside behind multiple PCCs that are connected on a single lateral or a single feeder. Some DR systems may already be interconnected, while others are planned for the future, and thus need to be taken into account. This lack of exact sizing cut-offs mean that studies will be needed to determine not only which (if any) DR functions should be required but also what settings for those functions should be initially established, and when should those settings be updated as additional DR systems are interconnected.

6.3.3. Types of Communications between the EPS Operator and DR SystemsColumn 3 in Table 6-1 recommends the types of communications that could be used between the EPS operator and DR systems for the different sensitivities and DR sizes. These recommendations range from “no communications are needed” to “communications and coordinated protection are required”. These recommendations include:


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Autonomous operation of the DR system with no data communications, although updates of autonomous settings may be made during maintenance activities. Alternatively, the EPS operator may talk to the DR managers to request changes of certain autonomous settings.

Direct communication paths are provided so that the EPS operator can exchange data directly (continuous real-time monitoring and control) with individual DR systems or with a DR management system that coordinates groups of DR systems.

Broadcast or multicast communications are provided for immediate real-time commands, so that the EPS operator may broadcast emergency commands (for reliability or safety purposes), while not necessarily interacting one-to-one with the DR systems.

Requests to change DR function modes (e.g. to improve efficiency) or updates to settings for groups of DR systems either directly or through a DR management system that coordinates groups of DR systems (e.g. on a campus).

Examples of EPS operator commands or requests (depending upon tariffs and other contractual agreements) include: Command to disconnect the DR system from the Area EPS for reliability or safety purposes.

Command to turn on the DR system to provide additional energy.

Command to increase power output of DR system to a specific value or to a percentage of maximum real power (applicable to controllable DR generators and to DR storage).

Command to limit real power output of DR system below a percentage of maximum real power to avoid over-generation situations.

Command to generate a percentage of available reactive power (leading or lagging).

Command to enable low/high voltage ride-through to prevent outages due to voltage spikes or sags.

Command to enable low/high frequency ride-through to prevent outages due to short-term frequency excursions.

Command to form a pre-planned island or microgrid.

6.3.4. EPS Operator Monitoring of Real Power, Reactive Power, and Voltage at the PCCColumn 4 in Table 6-1 recommends different levels of monitoring DR output characteristics at the PCC. The EPS operator monitors the real power, reactive power, and voltage at the PCC, but does not directly control the DR systems. The following information exchanges will be supported by DR systems at the PCC (the same as for the original IEEE 1547) for real-time monitoring: Monitor the connection status

Monitor real power, reactive power, and voltage

6.3.5. DR and EPS ProtectionColumn 5 in Table 6-1 recommends different protection requirements for the different scenarios. Individual DR units typically include anti-islanding protection, protection of the DR unit, and protection of the EPS to the extent that the DR unit can damage the EPS. With high penetrations of DR or with large DRs, the necessity of considering the protection of the EPS becomes more important and complex, particularly as some of the DR functions try to ride-through or prevent the DR from disconnecting from the Area EPS.

With very low penetration and small DR, there is little or no impact on the functionality of the Area EPS protection system and the two protection systems may be designed independently. As the level of penetration or size of DR Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 30

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unit increases, the DR functions, the DR protection, and the Area EPS protection must function in a coordinated manner. Communication systems that may be used for these protection systems must be highly reliable. If they are not available, the protection system must default to local protective schemes and equipment.

A protection system that functions in a coordinated manner will consist of one or more protective functions designed to protect the DR, one or more protective functions designed to protect the Areas EPS, and isolating devices. In some cases, protective functions require communication channels (i.e. transfer trip, permissives, alternate protection settings). Some of the protection schemes will require communications with differing response times and availability requirements. Some typical protection options are: Option 1: Over-current protection on the Area EPS and anti-islanding protection on the DR

Option 2: Over-current protection and voltage sensing on the Area EPS, anti-islanding protection on the DR and directional over-current at the DR

Option 3: Over-current protection and auto ground or other protection practices on the Area EPS, directional over-current on the DR, single line section

Option 4: Distance or directional over-current protection, auto-grounds, multiple line sections

Option 5: Impedance or directional over-current protection and teleprotection, such as Transfer Trip (TT), Directional Comparison Blocking (DCB) or Permissive Overreaching Transfer Trip (POTT).

6.3.6. Communications for Autonomous DR Functions Column 6 in Table 6-1 recommends the types of autonomous DR functions listed in Annex K that can be implemented and activated with pre-established settings for the different DR scenarios. Although most of these DR functions can be executed autonomously, communications can greatly enhance their effectiveness. The EPS operator may desire to coordinate different DR systems in which DR functions should be executed using what parameters. The EPS operator may just initiate an advanced function, or may modify settings first, or may schedule the advanced function, etc. Although the selection of which DR functions must be implemented is up to regulators and the EPS operator, the most common autonomous DR functions that an EPS operator may require for interconnection include: Low/high voltage ride-through to prevent outages due to voltage spikes or sags.

Low/high frequency ride-through to prevent outages due to short-term frequency excursions

Commanded limiting of energy output

Commanded change of power factor to a different value

Autonomous volt-var management functions that modify reactive power output, based on voltage deviations from the nominal, as defined by volt-var curves

Autonomous dynamic reactive current support during abnormally high or low voltage levels, based on voltage-time curves and settings (commonly known as Low/High Voltage Ride-Through)

Autonomous frequency-watt management functions that respond to frequency deviations by modifying the real power output, based on frequency-watt curves, applicable to generation and to rates of charging storage such as electric vehicles as well as DR generators

Autonomous watt-power factor management functions that modify power factor based on real power being output

Autonomous voltage-watt management functions that smooth voltage deviations by real power management or that by modifying the rates of charging storage devices


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Pricing information for energy and/or ancillary services that may be used by DR systems to modify their output (Demand Response for DR systems).

6.3.7. Direct Management of DR SystemsColumn 7 in Table 6-1 recommends the DR functions that the EPS operator could use to directly manage the DR systems. The EPS operator could manage these DR functions through direct commands to enter specific DR modes and/or to execute specific controls. Alternatively the EPS operator could issue schedules to the DR systems for entering specified modes or commands at specific times of the day, days of the week, days in the month, or season. These EPS operator management commands could be sent directly to individual DR systems, or could be sent through third-parties or facility energy management systems. These commands could include:

Request real-time information on DR status and capabilities

Receive direct responses from DR systems after commands are issued to ensure compliance

Update emergency action settings

Update autonomous mode settings

Set exact DR generation output and storage levels

Set exact power factor values

Send schedules for all actions, including modes and settings

7. Multiple DR in Area EPS ManagementClause 7 addresses the impacts of multiple DRs at multiple PCCs in an Area EPS as they affect DR performance in aggregate or as a group or groups. This clause does not directly address behavior of multiple DR behind a common PCC. Subclauses 7.1 through 7.4 discuss phenomena arising from group behavior of multiple DRs in an Area EPS. Subclause 7.5 discusses the use of DR as a tool for managing the power system and to enhance Area EPS performance.

Operations of multiple DRs connected at multiple PCCs to a common circuit or within the Area EPS result in a composite impact on the Area EPS loading and voltage and var situation, depending on the correlation between the behavior of the DRs and correlation with other EPS volt/var controlling devices and on locations of different DR in relation to the EPS source of supply. For example, an individual DR may not have a significant impact on power flow or voltage within a distribution circuit, where a group of DRs may cause reverse power flow or voltage fluctuations if their operating profiles are coincident.

DR exhibiting group behavior may extend to neighboring feeders or to the transmission and distribution system serving a region, particularly where DR output is significant compared to locally-served load (“high penetration”). For example, where feeder that is part of a voltage management scheme that relies more on the substation transformer tap than feeder-level voltage controls, DR on one feeder may impact feeder voltage or DR on neighboring feeders. Where feeder-connected DR is sufficient to export power from the feeder under some light load conditions, this could affect power flow, voltage, or loading in the transmission system; it may even affect the interconnection of generation in the transmission system.


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The group behavior of the DRs also diversifies the impacts of operations of individual DRs within the area EPS. A single large DR is likely to have greater impacts than two smaller DRs representing the same nominal capacity if the points of interconnection are different and the operating characteristics are at all diverse.

The impact of each additional DR (last DR) on the EPS operations depends on the mutual reactions of the entire group of DRs. The Area EPS operator should evaluate individual DR interconnections within the context of the Area EPS, existing DR, and other potential DR, for simultaneous or coincident operating profiles and for potentially compounding power flow or voltage impacts under a range of load conditions.

The operations and/or locations of individual DRs may be proactively coordinated by the Area EPS operator to avoid adverse results from compounding impacts of groups of DR. The Area EPS operator may also coordinate the impacts of groups of DR to improve Area EPS performance (discussed in Subclause 7.5).

Optimal operations of a group of DR within the area EPS require situational awareness about the group behavior of the DR and coordination of requests issued by the EPS for the DR operations and other EPS volt/var controlling devices.

It should be noted that while under IEEE 1547 DR attributes and requirements are to be applied at the PCC, IEEE 1547.1 and UL 1741 tests are applied AT THE TERMINALS OF THE INVERTERS. The result is a system that typically responds to the LOW voltage system, and NOT at the PCC. For successful evaluation and management of DR group behavior, the voltages and currents MUST be calculated at the individual DR PCC. This will eliminate many of the concerns with low side measurements and some interface transformer connections.

DR “penetration,” or output relative to locally-served load, and group behavior of DRs are related concepts. For purposes of this Clause 7 we assume DRs in the Area EPS having sufficient “penetration” to explicitly create the potential for interactions or create the opportunity for EPS benefits through coordination.

It should be noted that while under IEEE 1547 DR attributes and requirements are to be applied at the PCC, IEEE 1547.1 and UL 1741 tests are applied AT THE TERMINALS OF THE INVERTERS. The result is a system that typically responds to the LOW voltage system, and NOT at the PCC. For successful evaluation and management of DR group behavior, the voltages and currents MUST be calculated at the individual DR PCC. This will eliminate many of the concerns with low side measurements and some interface transformer connections.

We all agreed that this does not fit in clause 7 but I am hesitant to add that to clause 5. What if in the future UL decides to do type tests for multiple DR at least in a smaller scale? Then our statement will not be valid anymore. I don't think the above paragraph adds any value to the document so I would recommend that we delete it. Please let me know if you still think we should keep it. I will do my best to re-word it such that it fits within the scope of clause 5. I also don't like the idea of mentioning UL's name in the document. I am sure there are other labs in the world that do similar certification. I would recommend using " independent recognized test laboratory" instead of UL.

7.1. Interference with Anti-Islanding ProtectionUnder high penetration of DR, multiple PV systems (for example) may be connected to the same distribution line. Interactions between these DRs may increase the chance of sustaining an unintended island or interfere with the performance of active anti-islanding features. The following are examples of recommended practices.

7.1.1. Mix of Inverter-based and Rotating DR in Area EPS


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Where there is a mix of inverter-based and rotating DR (or other rotating machines) in the Area EPS, under fault conditions within the separated portion of the Area EPS it may be possible for inverter-based DR (particularly PV) to provide a continuing source of excitation voltage and it may be possible for the rotating DR to provide a continuing source of reactive power to sustain the island. There may be additional interactions, such as rotating generation being mistaken for the utility source and interfering with the anti-islanding protection.

Therefore, the anti-islanding test circuit of inverter-based DR should be considered to include the rotating machine.

7.1.2. Conflicts in Island DetectionIt is conceivable that inverters from different manufacturers, as well as more conventional rotating generation may interact in ways that are not immediately obvious. For example, the inverter manufactures generally consider the ‘anti-islanding’ as trade secret information, and generally are not willing to discuss the specific details of how their equipment operates. Therefore, it is conceivable that inverter A will operate in such a manner that inverter B will ‘see’ it as a valid EPS system, and not an island condition. It is not obvious how this situation can be predicted, avoided, or corrected without specific information from the manufacturers. Therefore the only reasonable course of action is to assume the worst case [the inverters WILL interfere with each other in term of island detection], and design the Area EPS system to be sufficiently robust to properly handle the resulting situation. Essentially a defense in depth approach.

7.1.3. Interference of Active Anti-IslandingInverter-based small-scale DR is often equipped with active anti-islanding protection which injects perturbation signals into the Area EPS. This is done in an attempt to create an abnormal condition in voltage or frequency when unintentional islanding occurs.

While active anti-islanding protection has an advantage in that it has a small NDZ (Non-Detection Zone), under high penetration of DR active anti-islanding can fail to detect islanding within the prescribed time because of cancellation of perturbation signals from different DR connected in high density.

Also, power quality in the Area EPS in a normal operation could be adversely affected by perturbation signals.

In order to address the problem of failure in islanding detection by active anti-islanding protection due to cancellation of perturbation signals, testing is conducted with various combinations of various inverter-based interconnection systems to verify that unintentional islanding can be detected in an appropriate time frame.

The following points should be considered in the test:

Active anti-islanding protection methods should detect the unintentional islanding without the interference of active signals with each other.

Islanding should be detected even when generations and loads within the island are balanced.

In normal condition power qualities of the Area EPS should not be degraded by perturbation signals.

However, conducting the above-mentioned test requires a large-scale test facility and a great deal of time and effort to because of the vast number of combinations. There are various types of active anti-islanding protection methods and implementation differs depending on the manufacturer even within the same equipment classification.


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One of the ways to save time and effort when conducting the above-mentioned test is to autonomously synchronize perturbation signals in an island with multiple inverter-based DR interconnections [ref: NEDO, Frequency Feedback Method with Step Injection]. Background and details are included in Annex J.

7.2. Voltage Oscillation due to DR Control InteractionIt is conceivable that the voltage controls of one or more DR could interfere with those of another DR. This is especially true with systems that have similar time constants and high gain. They may very well develop an oscillation. Voltage controls set in such a manner to limit interference may be a suitable approach. For example the use of hysteresis, time delays, and if necessary, communication, may provide a stable environment.

7.3. Group Variation of DR OutputPhotovoltaic generation is subject to rapid variations in output due to changes in solar radiation. The range of variation within 60 seconds can be as much as 50% of rated output [ref: Lenox]. Moreover, in principal changes in solar radiation due to some regional factor such as a cloud passing could affect PV projects in the Area EPS as a group, causing their output to change simultaneously. However, research [ref; Kleissl] suggests that there is a significant “geographic smoothing” effect on the variability of the aggregate output of groups of PV projects (and concomitant voltage impacts) experienced by the power system in a system with multiple PV interconnections.

Changes in solar radiation arise from unpredictable (difficult-to-forecast) phenomena, such as clouds passing under partly cloudy conditions or burn off of coastal fog. Changes in solar radiation also arise from predictable (forecastable) phenomena such as sunrise and sunset.

In some instances high penetration of DR with variable and/or unpredictable output has changed the spinning reserve requirements of the Area EPS. In effect the Area EPS must maintain spinning reserves to compensate for possible unforeseeable simultaneous increases or decreases in the output of these DR in addition to the reserves to compensate for the unforeseeable changes in load and available output from conventional resources already incorporated in capacity planning. This has required the Area EPS to accelerate capital investments in additional generation source(s) which can provide that quicker spinning reserve response rate.

Wind generation is prone to output variability due to wind gusts. In addition, relatively steady prevailing winds can decline under heat or storm conditions, potentially unpredictably affecting as a group a large share of the wind generation within an Area EPS. Where wind generation is high relative to served load within the Area EPS such conditions can result in a problematic decrease in available wind energy at a time when loads are at their peak.

7.3.1. TestingTime series operational data from existing PV generation units within a region or from solar irradiation sensors may indicate the coincidence in output variation among PV projects due to changes in solar radiation.

7.3.2. Best PracticesWhere solar sensor or PV project output data suggest that one or more PV projects may be reasonably expected to change output unexpectedly and simultaneously, the impact of these projects on Area EPS voltage and power flow should be evaluated considering the projects as a group.

If PV projects changing output simultaneously due to changes in solar radiation has impacts on Area EPS in terms of voltage or power flow that require mitigation, it is appropriate to address the impacts of predictable changes in solar radiation, such as sunrise and sunset, differently from the impacts of unpredictable changes in solar radiation such as passing clouds or coastal fog burn off.


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If wind and solar radiation forecasting capability improves, the predictability of the output of PV and wind generation should also increase. In that case it is appropriate to address the impacts of predictable output changes differently than the impact of unpredictable output changes.

7.4. Group Trip on Voltage or Frequency ExcursionsAn Area EPS voltage or frequency excursion is perhaps the best example of a scenario that could trigger essentially simultaneous group behavior of DR in the Area EPS. Best practices for addressing this concern are discussed in detail in Clause 4.2. It is noted here due to the group behavior implications of the event.

DR group response to an Area EPS voltage or frequency excursion could also result in sufficient loss of generation capacity within the Area EPS to lead to a cascading emergency in the Area EPS. The potential for such an event is a function of the combined DR output relative to load at the time of the event and the characteristics of the Area EPS.

7.4.1. Best PracticesThe Area EPS Operator should update contingency analyses periodically to anticipate when aggregate DR output relative to load approaches this possibility. Best practices for addressing this concern are discussed in detail in Clause 4.2.

7.5. DR as a Tool for Managing Power SystemsJust as DR systems challenge traditional power system management, DR systems individually or in groups could also become very powerful tools in management of the Area EPS to improve Area EPS performance. Given the increasingly sophisticated capabilities of DR, Area EPS operators are increasingly desirous (and even mandated by some regulations) to make use of these capabilities to improve Area EPS performance. [See CA Rule 21 I-DER Technical Requirements]. This subclause discusses the types of Area EPS performance benefits DR can contribute to and the role(s) DR can serve to contribute to those benefits, and provides recommendations in terms of specific DR functions, attributes, and coordination approaches that support those benefits. A list of DR functions is provided in Annex K.

DR systems are capable of providing many functions that support power system operations or contribute to grid benefits. Many of these inverter-based functions are described in the Advanced Functions for DR Systems Modeled in IEC 61850-90-73. Most DR systems can or must operate autonomously in order to meet power system safety, reliability, and efficiency criteria, but communications can provide additional functionality. At the same time, direct control by utilities is not feasible for the thousands if not millions of DR systems connected to the distribution system, so a hierarchical approach is necessary for utilities to interact with these widely dispersed DR systems and use them as a tool in power system management.

The majority of DR systems use inverters to convert their primary electrical form (often direct current (DC) or non-standard frequency) to the utility power grid standard electrical interconnection requirements of 60Hz or 50Hz and alternating current (AC). Not only can inverters provide these basic conversions, but inverters are also very powerful devices that can readily modify many of their electrical characteristics through software settings and commands, so long as they remain within the capabilities of the DR system that they are managing and within the standard requirements for interconnecting the DR to the Area EPS. In addition, synchronous generators and induction

3 See “Advanced Functions for DR Systems Modeled in IEC 61850-90-7” at http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/IEC61850-7-420_Overview The actual IEC 61850-90-7 Technical Report is available through the IEC.


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generators can provide some of the DR functions, so long as they are not incompatible with the capabilities and limitations of those generators.

Different DR scenarios, use cases, and functionalities as applied to Area EPS management dictate different communication and control needs. DR systems increasingly have the capability to perform advanced functions “autonomously” according to pre-established settings or “operating modes”, with sensing of and response to local voltage, frequency, or temperature conditions to modify their power and reactive power output. DR with such functionality may still respond to occasional commands to override or modify their autonomous actions by utilities and/or energy service providers (ESPs). These autonomous DR functions along with the ability to remotely update settings and schedules and override actions can allow Area EPS operators to better coordinate these DR for power system management while minimizing the need for constant communications. Best practices for DR monitoring, information exchange and control are discussed in Clause 6.

DR within an Area EPS, individually or in groups, can potentially enhance the performance of the Area EPS in terms of the following Area EPS performance benefit categories. In each case the relevant role of DR is described.

Reliability Improvement

DR in the Area EPS directly reduces the duration or frequency of customer outages or reduces the risk of customer outages, generally expressed in terms of indices of customer interruption duration or frequency. The basic method for this improvement is through high/low voltage ride-through as well as high/low frequency ride-through, which permits the DR systems to remain connected during these anomalies for a longer period of time. Other DR functions permit the DR systems to try to counteract these voltage spikes and sags and to modify energy output to counteract high and low frequency. An additional method is the formation of microgrids that continue to provide power to the local EPS even when the area EPS is de-energized.

Load Relief

DR in the Area EPS offsets local load or reduces its output to directly relieve an identified actual or potential overload that would otherwise require a capital project. This could include possible overloads due to the DR itself.

Bulk System Energy and Demand Capacity

DR in the Area EPS provides incremental energy and/or demand capacity contributing to bulk system or “resource adequacy” capacity requirements. In particular DR can contribute to peak shaving requirements. DR energy storage in particular can provide rapid response to increase demand requirements.

Improved Voltage Power Quality

DR in the Area EPS directly counteracts rises and dips in voltage levels to keep voltage within the normal voltage range. In particular, DR can manage voltage at the end of long weak feeders that might not otherwise be able to support the export of DR energy. Voltage variability is generally expressed in terms of event magnitude and duration curves.


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Efficiency improvement through Conservation Voltage Reduction

DR in the Area EPS directly helps maintain CVR voltage levels, expanding the opportunities for CVR (see Annex 7.3). DR attributes and functions to support CVR are voltage management attributes and functions. Expanded CVR as an Area EPS performance objective is distinct from power quality improvement or voltage violation relief.

Enhanced System Voltage Security

DR in the Area EPS provides fast-response real or reactive power during Area EPS frequency or voltage excursions, directly damping or reducing propagation of a voltage collapse event. DR also reduces large or rapid voltage variability that could otherwise result in outages or damage to customer equipment.

Ancillary Services Capacity

DR in the Area EPS provides additional ancillary services capabilities, such as providing reserve energy, var support, frequency support, and black start capabilities,

Reduced Congestion

DR in the Area EPS directly reduces energy deliveries over congested paths, reducing congestion charges. DR attributes and functions to reduce congestion are local load-offsetting attributes and functions; however, congestion relief as an Area EPS performance objective is distinct from load relief.

Efficiency Improvement through Loss Reduction

DR in the Area EPS directly reduces net Area EPS losses otherwise incurred to serve Area EPS end-user load.

Voltage Violation Relief

DR in the Area EPS directly reduces an identified actual or potential steady-state voltage violation in the Area EPS. This could include DR having attributes or functions to relieve possible voltage violations due to the DR itself.

Lower Cost Energy

DR in the Area EPS provides incremental energy that is lower cost than bulk generation. Beneficial bulk system energy may result from lower marginal cost energy from individual DR or from DR attributes and functions allowing operational coordination to reduce overall Area EPS production costs.

Smooth Power Output Transitions

After power is restored to an Area EPS, the DR ramps up or reconnects randomly within a time window in order to avoid sharp increases in power which could cause equipment damage or even another outage. Ramping can also be used to avoid sharp transitions between energy output levels, such as might be caused by fluctuations in wind or solar energy or by changing scheduled output levels.


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Emission Reduction

Renewable DR in the Area EPS directly results in a net reduction in emissions to serve Area EPS load. Emission reduction may result from lower marginal emissions from individual DR or from DR attributes and functions allowing operational coordination to reduce overall Area EPS emissions.

Renewable Energy Credits

Renewable DR in the Area EPS provides incremental renewable energy credits (RECs) to help meet Renewable Portfolio Standard (RPS) goals.

The needs of each Area EPS will serve to prioritize these benefit categories for each Area EPS. Further, in some cases one benefit may conflict with another – for example, using DR to manage voltage by absorbing VArs may also increase losses.

Not all DR yield all Area EPS performance benefits; on the contrary, the potential for direct Area EPS performance benefits from DR is dependent upon the individual DR projects’ locations within the Area EPS, their size and operating characteristics, and the characteristics of the EPS itself overall and at the PCCs of the DR. As one example, only DR representing a particular amount of capacity, in a particular location, and delivering output under a particular set of operating conditions could meaningfully reduce loading on a key Area EPS component to avoid a capital project that would otherwise be required. Another example is where a DR interconnection at the end of a long weak circuit might cause voltage problems and/or overloads on the circuit unless the DR actively manages the voltage at that site or even limits energy output.

Effective use of DR to enhance Area EPS performance may benefit from a very detailed understanding of the Area EPS that indicates, for example, specific Area EPS locations where voltage variability is high or where DR would effectively offset voltage variation.

DR systems are capable of providing many functions that support power system operations or contribute to grid benefits. Many of these inverter-based functions are described in the Advanced Functions for DR Systems Modeled in IEC 61850-90-74. Most DR systems can or must operate autonomously in order to meet power system safety, reliability, and efficiency criteria, but communications can provide additional functionality. At the same time, direct control by utilities is not feasible for the thousands if not millions of DR systems connected to the distribution system, so a hierarchical approach is necessary for utilities to interact with these widely dispersed DR systems and use them as a tool in power system management.

Accordingly, where Area EPS performance benefits are attributed to individual DR or groups of DR, these benefits should demonstrably result directly from the specified DR and should be discrete, measurable, and predictable.

Table 4 in Annex K illustrates DR capabilities, specific DR inverter functions, communication requirements, DR attributes and coordination in planning and operations that may be appropriate for the use of DR to achieve certain Area EPS performance benefits. Table 4 shows that to achieve a given Area EPS performance benefits, an Area EPS

4 See “Advanced Functions for DR Systems Modeled in IEC 61850-90-7” at http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/IEC61850-7-420_Overview The actual IEC 61850-90-7 Technical Report is available through the IEC.


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operator should seek specific DER features and functionalities and should incorporate specific approaches in planning and operations. It is evident in Table 4 that some Area EPS performance benefits are enabled by more than one DR function, and some DR functions support more than one Area EPS performance benefit. Bibliography

1. Report to NIST on the Smart Grid Interoperability Standards Roadmap, June 2009; http://nist.gov/smartgrid/InterimSmartGridRoadmapNISTRestructure.pdf

2. Distribution Grid Management (Advanced Distribution Automation) Functions. Use Case Description, submitted to the SGIP DEWG, PAP8, 2/2010. Available: http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/PAP08DistrObjMultispeak/Distribution_Grid_ManagementSG_UC_nm.doc

3. Applications of Advanced Distribution Automation in the Smart Grid Environment, Nokhum Markushevich, T&D Online Magazine, January-February 2010 issue. Available: http://www.electricenergyonline.com/?page=mag_archives

4. Distribution Automation and Demand Response, N. Markushevich and A. Berman, DistribuTech2008, Tampa, FL, January, 2008; North American Policies and Technologies, Electricity, Transmission & Distribution, 2008, Volume 20, No. 8 ; 2009, Volume 21, No. 1 http://www.electricity-today.com/download/issue8_2008.pdf; http://www.electricity-today.com/download/issue1_2009.pdf

5. Integrated Voltage, Var Control and Demand Response in Distribution Systems, Nokhum Markushevich and Edward Chan, IEEE, March 2009, Seattle

6. Understanding Coordinated Voltage and Var Control in Distribution Systems: Is Power Factor = 1 Always a Good Thing?, Nokhum Markushevich, Energy Pulse, 2007, http://www.energypulse.net/centers/article/article_display.cfm?a_id=1553

7. The Specifics Of Coordinated Real-Time Voltage And Var Control In Distribution, Nokhum S. Markushevich, Utility Consulting International (UCI), Distributech 2002 Conference

8. Benefits of Utilizing Advanced Metering Provided Information Support and Control Capabilities in Distribution Automation Applications, EPRI Product ID 1018984, Technical Update,: December 2009.

9. Northwest Energy Efficiency Alliance. Distribution. Efficiency Initiative Project, Final Report, 2007. Available: http://www.comedamifuture.com/Resources/DEI%20Final%20Report%201207.pdf

10. 3-phase Conservation Voltage Reduction Analysis, Freeman Sullivan & Co. prepared for MicroPlaned Lt., 2006. Available: http://www.microplanetltd.com/upload/pdf/3-Phase_Analysis_Final_12-15-06_(2).pdf

11. Distribution Volt and Var Control in Emerging Business Environment, Nokhum Markushevich and Ron Nielsen, CEA Technologies Distribution Automation Seminar, Halifax, Nova Scotia, Canada. June, 2003


13. N. S. Markushevich, R. E. Nielsen, J. M. Hall, A. K. Nakamura, R. L. Nuelk, “Impact Of Automated Voltage/Var Control In Distribution Power System Operations”, DisitrbuTech, 1996.

14. Alf Dwyer, R.E. Nielsen, Joerg Stangl, and N.S. Markushevich, “Load to Voltage Dependency Tests at B.C. Hydro”, IEEE/PES 1994 Summer Meeting, July 1994

15. Nokhum S. Markushevich, Voltage and Var Control in Automated Distribution Systems, DA/DSM Conference, January 1993, Palm Springs, California (Description of the methodology and impacts of integrated Volt/var control in distribution system operations, including voltage impacts on load and losses).


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http://www.microplanetltd.com/upload/pdf/3-Phase_Analysis_Final_12-15-06_(2).pdf

http://www.comedamifuture.com/Resources/DEI%20Final%20Report%201207.pdf

http://www.energypulse.net/centers/article/article_display.cfm?a_id=1553

http://www.electricity-today.com/download/issue1_2009.pdf

http://www.electricity-today.com/download/issue8_2008.pdf

http://www.electricenergyonline.com/?page=mag_archives

http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/PAP08DistrObjMultispeak/Distribution_Grid_ManagementSG_UC_nm.doc

http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/PAP08DistrObjMultispeak/Distribution_Grid_ManagementSG_UC_nm.doc

http://nist.gov/smartgrid/InterimSmartGridRoadmapNISTRestructure.pdf


16. B.W. Kennedy and R.H. Fletcher, "Conservation Voltage Reduction (CVR) at Snohomish County PUD", IEEE Transactions of Power Systems, Vol. 6, NO. 3, pp. 986-998, August 1991

17. Daniel Kirshner, "Implementation of Conservation Voltage Reduction at Commonwealth Edison", IEEE Transaction of Power Systems, Vol.5, No.4, pp. 1178-1182, November 1990.

18. Erickson, J.C. and Gilligan, S.R., "The Effects of Voltage Reduction on Distribution Circuit Loads", IEEE Transactions on Power Apparatus and Systems, Vol. PAS-101, No. 7, July 1989, pp. 2014-2018.

19. Warnock, V.J. and Kirkpatrick, T.L., "Impact of Voltage Reduction on Energy and Demand", IEEE Transactions on Power Systems, vol. PWRS-1, No., May 1986, pp. 92-97.

20. Chen, M.S., Shoults, R. and Fitzer, J., "The Effects of Reduced Voltages on the Efficiency of Electric Loads", IEEE Transactions on Power Apparatus and Systems, Vol. PAS-101, No. 7, July 1982, pp. 2158-2166.

21. Carr, J., "Voltage Reductiont1, Report for the Canadian Electrical Association, February 1980. 22. Wheeler, P.L., Dickenson, A.H. and Gibbs,T.J., "The Effect of Voltage Reduction on Distribution System

Loads, IEEE Conference Paper A-78-542-3, Presented at the Summer PES Meeting, Los Angeles, July 16-21, 1978.

23. Priess, R.F. and Warnock, V.J., "Impact of Voltage Reduction on Energy and Demand", IEEE Transactions on Power Apparatus and Systems, Vol. PAS-97,No. 5, Sept./Oct. 1978, pp. 1665-1671.

24. NIST reviews impact of conservation voltage reduction for electric power industry. Available: http://findarticles.com/p/articles/mi_m0IKZ/is_2_107/ai_87701396/

25. Evans, Peter (New Power Technologies), “Verification of Energynet Methodology”, California Energy Commission, PIER Energy Systems Integration Program, CEC-500-2010-021, 2010.

26. Navigant Consulting, “Value of Distributed Energy Resources in Distribution Infrastructure; Phase II—Operational Assessment”, Final Report, National Energy Technology Laboratory RDS Contract DE-AC26-04NT41817, October 2008.

27. Evans, P., “Optimal Portfolio Methodology for Assessing Distributed Energy Resources for the Energynet”; CEC-500-2005-096, March 2005. Available: http://www.energy.ca.gov/2005publications/CEC-500-2005-096/CEC-500-2005-096.pdf

28. Nokhum Markushevich, The Benefits and Challenges of the Integrated Volt/Var Optimization in the Smart Grid Environment, , Accepted for presenting at IEEE GM 2011

29. Nokhum Markushevich, Cross-cutting Aspects of Smart Distribution Grid Applications, , Accepted for presenting at IEEE GM 2011

30. Nokhum Markushevich and Wenpeng Luan, Achieving Greater VVO Benefits through AMI Implementation, Accepted for presenting at IEEE GM2011

31. Nokhum Markushevich, Some Considerations of Operations of PV inverters in Electric Power Systems, Available: http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/TnD/Some_Considerations_of_Operations_of_PV_Inverters_in_Electric_Power_Systems.pdf

32. CERTS, May 2007, Demand Response Spinning Reserve Demonstration, LBNL-62761.

8. Functionality of the DR island system

This section applies to the requirements set forth in IEEE Std 1547.4 and provides recommended practices that may expand the usefulness and uniqueness of IEEE Std 1547.4 through the identification of innovative designs, processes, and operations.


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http://www.energy.ca.gov/2005publications/CEC-500-2005-096/CEC-500-2005-096.pdf

http://findarticles.com/p/articles/mi_m0IKZ/is_2_107/ai_87701396/


8.1.Area EPS-connected mode (normal parallel operation)This section recommends some practices in reference to the IEEE 1547.4 sub-clause 4.4.1.

Recommended Practice:

Area EPS operator should approve the sustainability of the island.

The automatic sectionalizing devices should be capable of communicating with the area EPS operator via real time telemetry.

Remote Terminal Unit (RTU) or any relay that meets the Area EPS Operator communication protocol requirements, i.e. DNP3, MODBUS, and etc. is recommended to be installed at the DR site.

Metering (Amperes, Voltage, real/reactive Power, frequency, and time stamp) with two way communications is recommended to be installed at the automatic sectionalizing devices.

8.2.Transition-to-island modeThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 4.4.2.

Recommended Practice: For the distribution level islands, Pulse Based Power Line Carrier (PLC) is recommended to be

installed at the distribution bus [1]. The DRs, that are planned to be included in the island, will sense the island formation once the PLC signal is lost. Proper communication is needed to disconnect the unplanned load from the island.

SCADA based communications between the automatic sectionalizing devices and the DR may be considered as well.

The relays at the DRs, that are planned to be included at the island, are recommended to be set to ride through the system transients, which varies based on the system stiffness factor. The Under Frequency Load Shedding and VAR match technology is recommended to be set to operate prior to the DR relays.

8.3. Island modeThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 4.4.3.

Recommended Practice:

For ground faults on four wire distribution circuit, where a ground fault current source is provided by the interconnecting entity, since the fault current contribution from the DR to the system ground faults is much smaller than that of the Area EPS, it is recommended to install voltage controlled over current relay on each DR to detect the grid ground faults. The pickup of


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the voltage controlled over current relay can be set below the nominal rating of the DR. All parallel DR relays should coordinate with the mainline relays/reclosers. The voltage controlled over current relay might not be able to detect the low fault current contribution from the DR. An alternative to the voltage controlled over current relay is zero sequence current detection from a detectable fault current source.

For three wire distribution circuits, or where the DR does not provide an effectively grounded source, it is recommended to detect the L-G faults by a voltage controlled negative sequence or a zero sequence over voltage relay [2].

The DR relays are recommended to be set to ride through the temporary faults within the island.

8.4.Reconnection modeThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 4.4.4.

Recommended Practice: During the open transition reconnection mode, the island load is recommended to be switched

online in small steps to avoid high in-rush current due to induction motor load. The induction motor absorbs a large amount of reactive power during the start-up, which results in transient behavior of the EPS system (Inrush current).

All DRs should be able to detect the grid connected mode (receive the PLC signal, or SCADA, etc.) and the relay settings are recommended to be changed to the pre-islanded mode values.

8.5.Load requirements and planningThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 5.1.

Recommended Practice: It is recommended to allow DR to maintain the island frequency and voltage by adjusting the

active and reactive power generation. The response time to the load disturbances is recommended to be quicker than the voltage and frequency relays in the island [3].

The voltage, frequency, and over current relays are recommended to be set ride through the island switching transients.

If the island imbalance is not within the acceptable range, it is recommended to allow more single phase generation on the heavily loaded phases to maintain the phase load balance.

In order to avoid ground relay nuisance tripping in an unbalanced island, it is recommended to make the ground relays voltage controlled. The ground relay will only operate during the island fault.

8.5.1. Reactive power considerationsThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 5.1.2.Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 43

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Recommended Practice: It is recommended to install reserve reactive power sources for the island, i.e. STATCOM,

capacitor banks, etc.

If the reactive power source is lacking, it is recommended to disconnect the non-critical load from the island to balance the reactive power. The DR must be able to stabilize the voltage by disconnecting portion of the non-critical load.

8.5.2. TransformersThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 5.1.3.

Recommended Practice: In order to avoid nuisance tripping during transformer inrush, the timer setting of all over current

relays in the island are recommended to be set such that the system rides through the transformer inrush current.

Start up series reactance or impedance is recommended to be installed to limit the inrush current. In order to avoid additional system losses, the installed reactance or impedance must be bypassed during normal system operation when the inrush current is diminished.

8.5.3. MotorsThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 5.1.4.

Recommended Practice: If the motor inrush is a concern, the recommended solutions in the transformer section may be

applied.

8.5.4. LightingThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 5.1.5.

Recommended Practice: It is recommended to install active or passive low pass filters in series with the load or high pass

filters in parallel to the mainline of the island if the harmonic distortion level is not acceptable due to a large amount of fluorescent ballast lights.

8.5.5. Load power qualityThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 5.1.7.

Recommended Practice: It is recommended to install active or passive low pass filters in series with the load or high pass

filters in parallel to the mainline of the island if the harmonic distortion level is a concern.


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8.5.6. Compatibility of grounding among the DR, transformer, and EPSThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 5.2.1.

Recommended Practice: For the four wire multi-grounded-neutral island, where the DR is not grounded, it is

recommended to install primary Yg, secondary Delta interconnection transformer, with grounding impedance on the neutral of the Yg winding sized by the area EPS operator to limit the DR contribution to ground faults.

For the four wire multi-grounded-neutral island, where the DR is grounded, it is recommended to install primary Yg, secondary Yg transformer with an effectively grounded source. Rotating generators must have a Yg stator winding and inverter based generators must have an internal primary Yg, secondary Delta transformer. The fault current contribution of the inverter is limited to 100%-140% of the rating in the steady state mode. Hence, grounding impedance might not be required.

If the DR does not provide an effectively grounded source, a grounding bank is recommended to be installed at either low side or high side of a Yg/Yg interconnection transformer or primary side of a primary Delta transformer.

8.5.7. Frequency regulationThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 5.2.3.

Recommended Practice: It is recommended to set the island under frequency load/generation shedding scheme fast enough to

maintain the frequency within 5% of nominal, so as not to excite mechanical resonance frequencies of the turbine generator shaft system.

8.5.8. EPS power qualityThis section recommends some practices in reference to the IEEE 1547.4 sub-clause 5.2.5.

Recommended Practice: Upon the agreement with the area EPS operator, it is recommended to allow DRs to participate in

regulating the island voltage and reducing the voltage flicker.

Filters are recommended to be installed to minimize the harmonics content within an acceptable limit.

Bibliography:

1. W. Xu, G. Zhang, C. Li, W. Wang, G. Wang, J. Kliber, “A Power Line Signaling Based Technique for Anti-Islanding Protection of Distributed Generators—Part I: Scheme and Analysis”, IEEE Transactions on Power Delivery, vol. 22, July 2007, p. 1758-1766.


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2. B. Enayati, “Protection of Photovoltaic and Wind Generators” Proceedings of the 2012 IEEE PES Transmission and Distribution Conference and Exposition, Orlando, Florida

3. B. Enayati, A. K. Ziarani, T. H. Ortmeyer, “An intelligent power flow controller for autonomous operation of islanded micro-grids” Proceedings of the 34th Annual Conference of The IEEE Industrial Electronics Society (IECON), Orlando, Florida, 10-13 November 2008


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9. Extension beyond 10 MVA

One limitation of IEEE Std 1547 is that is applies to DR less than 10 MVA. The following are guidelines for the interconnection of DR greater than 10 MVA that could be applied beyond the base IEEE Std 1547 requirements on DR interconnected to distribution systems. Many distribution system feeders cannot support DR of this size. The recommended practices described in other clauses of this document also apply to DR greater than 10 MVA.

IEEE Std 1547 Clause 4.1.1 - Voltage regulation

Depending on size of DR (relative to area EPS strength of stiffness at the point of interconnection) and location of interconnection, the interconnected DR may be required to provide or absorb reactive power and/or follow a voltage schedule to maintain an acceptable voltage profile on the Area EPS with the addition of the new DR. The DR shall not cause the Area EPS service voltage at other Local EPSs to go outside the requirements of ANSI C84.1-1995, Range A.

Sufficient study of the Area EPS will have to be conducted in order to determine whether active voltage regulation or power factor control will be more appropriate. Such study may include steady state power flow studies, transient machine response studies to check the effect of voltage changes due to sudden DR changes (e.g. unexpected trip), and transient stability studies related to the surrounding power system.

IEEE Std 1547 Clause 4.1.4 Distributed resources on distribution secondary grid and spot networks

The recommendation is to not interconnect DR above 10 MVA on distribution secondary grid and spot networks.

IEEE Std 1547 Clause 4.2.1 - Area EPS faults

The DR unit shall cease to energize the Area EPS for faults on the Area EPS circuit to which it is connected unless different conditions are agreed to with the Area EPS operator.

IEEE Std 1547 Clause 4.2.3 - Voltage

When conditions warrant, the following extensions can be used, as needed. The DR response to over-voltage and under-voltage should be coordinated with the Area EPS to meet similar requirements as transmission-connected generators.

IEEE Std 1547 Clause4.2.4 Frequency

The DR response to over-frequency and under-frequency should be coordinated with the Area EPS to meet similar requirements as transmission-connected generators.

IEEE Std 1547 Clause 4.4.1 - Unintentional IslandingWhen conditions warrant, the following extensions can be used, as needed. The DR interconnection system shall detect the island and cease to energize the Area EPS within ten seconds of the formation of an island.

The unintentional islanding requirement can be met by the following:


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Transfer trip.Sensitive frequency and voltage relay settings, with a short tripping time delay, where the maximum DR aggregate

generation net output to the area EPS is considerably less than the expected minimum islanded area EPS load. DR certified to pass an anti-islanding test.Reverse or minimum power flow relay limited. Other anti-islanding means such as forced frequency or voltage shifting. Other anti-islanding means such as forced frequency or voltage shifting.


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Annex A (Informative) -- Bibliography

Bibliography

1. IEEE P1547-2003: IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems

2. P1547.2TM-2008: IEEE Application Guide for IEEE Std 1547™, IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems

3. Energy Independence and Security Act of 2007, Title XIII – Smart Grid, Available: http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=110_cong_bills&docid=f:h6enr.txt.pdf

4. G. Clark, Development of the Switched Capacitor Bank Controller for Independent Phase Switching on the Electric Distribution System, IEEE, GM 2010, Minneapolis

5. Distribution Grid Management (Advanced Distribution Automation) Functions. Use Case Description, submitted to the SGIP DEWG, PAP8, 2/2010. Available: http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/PAP08DistrObjMultispeak/Distribution_Grid_ManagementSG_UC_nm.doc

6. Development of Data and Information Exchange Model for Distributed Energy Resources, EPRI, Palo Alto, CA: 2010. 1020832. Available: http://my.epri.com/portal/server.pt?space=CommunityPage&cached=true&parentname=ObjMgr&parentid=2&control=SetCommunity&CommunityID=404&RaiseDocID=000000000001020832&RaiseDocType=Abstract_id


8. Report to NIST on the Smart Grid Interoperability Standards Roadmap, June 2009; http://nist.gov/smartgrid/InterimSmartGridRoadmapNISTRestructure.pdf

9. Distribution Automation and Demand Response, N. Markushevich and A. Berman, DistribuTech2008, Tampa, FL, January, 2008; North American Policies and Technologies, Electricity, Transmission & Distribution, 2008, Volume 20, No. 8 ; 2009, Volume 21, No. 1 http://www.electricity-today.com/download/issue8_2008.pdf; http://www.electricity-today.com/download/issue1_2009.pdf

10. IntelliGrid Architecture Development for Distribution Systems. Requirements and Device Information Models for Integrated Advanced Distribution Automation Applications, EPRI, Palo Alto, CA: 2008, 1013843

11. ADA_DER Use Cases, http://www.epri-intelligrid.com/intelligrid/docs/IECSA_VolumeII.pdf, 2004.12. F. Katiraei, Analysis of Voltage Regulation Problem for a 25-kV Distribution Network with

Distributed Generation, in Proc. of IEEE PES 2006 General Meeting, Jul 200613. M. R. Hesamzadeh, et al, Design and Study of a Switch Reactor for Central Queensland SWER

system, Universities Power Engineering Conference, 2008. UPEC 2008. 43rd International, Sep 200814. S. A. Miske, Considerations for the Application of Series Capacitors to Radial Power Distribution

Circuits, IEEE Transactions on Power Delivery, Vol. 16, No. 2, Apr 200115. Z. Hanzelka, A. Bien, Power Quality and Utilization Guide, Section 5.1.4, Voltage Disturbances –

Flicker, Copper Development Association, April 2006. Available: http://www.copperinfo.co.uk/power-quality/downloads/pqug/514-flicker.pdf

16. Advanced Power System Management Functions for Inverter-based DER Devices, Draft v.9b. Available: http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/PvInverter/Advanced_Functions_for_DER_Inverters_v9b.docx


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http://www.copperinfo.co.uk/power-quality/downloads/pqug/514-flicker.pdf

http://www.copperinfo.co.uk/power-quality/downloads/pqug/514-flicker.pdf


17. B. Seal, “Standard language protocols for photovoltaics and storage grid integration,” EPRI 1020906, Tech. Rep., 2010. Available: http://my.epri.com/portal/server.pt?Abstract id=000000000001020906

18. Petr Sulc, Konstantin Turitsyn, Scott Backhaus, Michael Chertkov, “Options for Control of Reactive Power by Distributed Photovoltaic Generators”. Available: http://arxiv.org/PS_cache/arxiv/pdf/1008/1008.0878v1.pdf

19. E. Liu and J. Bebic, “Distribution system voltage performance analysis for high-penetration photovoltaics,” NREL/SR-581-42298, Tech. Rep., 2008. Available: http://www1.eere.energy.gov/solar/pdfs/42298.pdf

20. Nokhum Markushevich, Mitigating Voltage Fluctuation Caused by Variability of Distributed Energy Resources, Available: http://www.energypulse.net/centers/article/article_display.cfm?a_id=2602

21. Eliminating voltage variation due to distribution-connected renewable generation Reigh Walling, GE

Energy Gao, Zhi, GE Energy, DistribuTech 2010.22. Charles J. Jensen, James C. Clemmer, and Nokhum S. Markushevich, Distribution Automation Pilot

Projects At JEA and OG&E. New Ideas for Remote Voltage and Var Control, DA/DSM Distributech Conference, January 1999


24. Integrated Voltage, Var Control and Demand Response in Distribution Systems, Nokhum Markushevich and Edward Chan, IEEE, March 2009, Seattle

25. Understanding Coordinated Voltage and Var Control in Distribution Systems: Is Power Factor = 1 Always a Good Thing?, Nokhum Markushevich, Energy Pulse, 2007, http://www.energypulse.net/centers/article/article_display.cfm?a_id=1553


27. Benefits of Utilizing Advanced Metering Provided Information Support and Control Capabilities in Distribution Automation Applications, EPRI Product ID 1018984, Technical Update, December 2009.

28. Northwest Energy Efficiency Alliance. Distribution. Efficiency Initiative Project, Final Report, 2007. Available: http://www.comedamifuture.com/Resources/DEI%20Final%20Report%201207.pdf

29. 3-phase Conservation Voltage Reduction Analysis, Freeman Sulivan & Co. prepared for MicroPlaned Lt., 2006. Available: http://www.microplanetltd.com/upload/pdf/3-Phase_Analysis_Final_12-15-06_(2).pdf

30. Distribution Volt and Var Control in Emerging Business Environment, Nokhum Markushevich and Ron Nielsen, CEA Technologies Distribution Automation Seminar, Halifax, Nova Scotia, Canada. June, 2003

31. The Specifics Of Coordinated Real-Time Voltage And Var Control In Distribution, Nokhum S. Markushevich, Distributech 2002 Conference

32. N. S. Markushevich, R. E. Nielsen, J. M. Hall, A. K. Nakamura, R. L. Nuelk, “Impact Of Automated Voltage/Var Control In Distribution Power System Operations”, DisitrbuTech, 1996.


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http://www.energypulse.net/centers/article/article_display.cfm?a_id=1553

http://www.electricenergyonline.com/?page=mag_archives

http://arxiv.org/PS_cache/arxiv/pdf/1008/1008.0878v1.pdf


33. Alf Dwyer, R.E. Nielsen, Joerg Stangl, and N.S. Markushevich, “Load to Voltage Dependency Tests at B.C. Hydro”, IEEE/PES 1994 Summer Meeting, July 1994

34. Nokhum S. Markushevich, Voltage and Var Control in Automated Distribution Systems, DA/DSM Conference, January 1993, Palm Springs, California (Description of the methodology and impacts of integrated Volt/var control in distribution system operations, including voltage impacts on load and losses).

35. B.W. Kennedy and R.H. Fletcher, "Conservation Voltage Reduction (CVR) at Snohomish County PUD", IEEE Transactions of Power Systems, Vol. 6, NO. 3, pp. 986-998, August 1991

36. Daniel Kirshner, "Implementation of Conservation Voltage Reduction at Commonwealth Edison", IEEE Transaction of Power Systems, Vol.5, No.4, pp. 1178-1182, November 1990.

37. Erickson, J.C. and Gilligan, S.R., "The Effects of Voltage Reduction on Distribution Circuit Loads", IEEE Transactions on Power Apparatus and Systems, Vol. PAS-101, No. 7, July 1989, pp. 2014-2018.

38. Warnock, V.J. and Kirkpatrick, T.L., "Impact of Voltage Reduction on Energy and Demand", IEEE Transactions on Power Systems, vol. PWRS-1, No., May 1986, pp. 92-97.

39. Chen, M.S., Shoults, R. and Fitzer, J., "The Effects of Reduced Voltages on the Efficiency of Electric Loads", IEEE Transactions on Power Apparatus and Systems, Vol. PAS-101, No. 7, July 1982, pp. 2158-2166.

40. Carr, J., "Voltage Reductiont1, Report for the Canadian Electrical Association, February 1980. 41. Wheeler, P.L., Dickenson, A.H. and Gibbs,T.J., "The Effect of Voltage Reduction on Distribution

System Loads, IEEE Conference Paper A-78-542-3, Presented at the Summer PES Meeting, Los Angeles, July 16-21, 1978.

42. Priess, R.F. and Warnock, V.J., "Impact of Voltage Reduction on Energy and Demand", IEEE Transactions on Power Apparatus and Systems, Vol. PAS-97, No. 5, Sept./Oct. 1978, pp. 1665-1671.

43. NIST reviews impact of conservation voltage reduction for electric power industry. Available: http://findarticles.com/p/articles/mi_m0IKZ/is_2_107/ai_87701396/

44. Evans, Peter (New Power Technologies), “Verification of Energynet Methodology”, California Energy Commission, PIER Energy Systems Integration Program, CEC-500-2010-021, 2010.

45. Navigant Consulting, “Value of Distributed Energy Resources in Distribution Infrastructure; Phase II—Operational Assessment”, Final Report, National Energy Technology Laboratory RDS Contract DE-AC26-04NT41817, October 2008.

46. Evans, P., “Optimal Portfolio Methodology for Assessing Distributed Energy Resources for the Energynet”; CEC-500-2005-096, March 2005. Available: http://www.energy.ca.gov/2005publications/CEC-500-2005-096/CEC-500-2005-096.pdf

47. Nokhum Markushevich, The Benefits and Challenges of the Integrated Volt/Var Optimization in the Smart Grid Environment, , Presenting at IEEE GM 2011

48. Nokhum Markushevich, Cross-cutting Aspects of Smart Distribution Grid Applications, , Presenting at IEEE GM 2011

49. Nokhum Markushevich and Wenpeng Luan, Achieving Greater VVO Benefits through AMI Implementation, Presenting at IEEE GM2011

50. CERTS, May 2007, Demand Response Spinning Reserve Demonstration, LBNL-62761.51. De Brabandere K., Voltage and Frequency Droop Control in Low Voltage Grids by Distributed

Generators with Inverter Front-End. Available: http://www.esat.kuleuven.be/electa/publications/fulltexts/pub_1610.pdf

52. Nokhum Markushevich, Some Considerations of Operations of PV inverters in Electric Power Systems, Available: http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/TnD/Some_Considerations_of_Operations_of_PV_Inverters_in_Electric_Power_Systems.pdf


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Annex B (Informative) -- DER Management Interaction ProcessesThere are three basic processes that can be used to manage DER systems, although many variations on these processes are possible:

Tightly-coupled interactions focused on direct monitoring and control of the DERs with responses expected in “real-time”.

– Tightly-coupled commands assume relatively detailed knowledge of the status and capabilities of the DER system.

– Tightly-coupled interactions would more likely be needed for grid reliability but could also be associated with grid efficiency.

– Common scenarios for tightly-coupled interactions are controllers that directly manage one or more inverters, such as a home PV system, a building with multiple PV systems, a wind farm, or a solar farm.

– Additional scenarios include an ISO/RTO managing a large storage device through Automatic Generation Control (AGC) or requesting a specific power factor at the PCC of a wind farm

– A microgrid scenario would include a microgrid management system tightly managing the formation of the microgrid and controlling the combined generation, storage, and load elements to maintain microgrid stability.

Loosely-coupled interactions which request actions or “modes” that are interpreted by intelligent DER systems for undertaking autonomous reactions to local conditions or externally provided information. Information is then sent back on what actions they actually performed.

– Autonomous behavior is defined as DER devices utilizing pre-set modes and schedules that respond to locally sensed conditions, such as voltage, frequency, and/or temperature, or to broadcast information, such as pricing signals or requests for using specific modes. These pre-settings are updated as needed (not in real-time), possibly through the Internet or through other communication methods.

– Loosely-coupled interactions would be more likely associated with grid efficiency than with grid reliability, but could also be used for emergency commands.

– Common scenarios for loosely-coupled interactions include a campus DER management system coordinating many DER systems on different buildings or an energy service provider managing disparate DER systems within a community.

Broadcast/multicast essentially one-way requests for actions or “modes”, without directly communicated responses by large numbers of DERs.

– These broadcast or multicast requests are interpreted by the DER systems for undertaking autonomous reactions to local conditions or externally provided information.

– Broadcast/multicast requests would be more likely associated with grid efficiency than with grid reliability because of the uncertainly of DER responses, but could also be used for emergency commands.

– Broadcast/multicast can be used to request actions without necessarily knowing which DER systems can or will respond, thus setting the expectation that only a certain number will


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respond without a direct measure of how much each responded (at least in real-time – metering information can provide after-the-fact measures). The amount of response would be determined by monitoring the power system to see whether

– Common scenarios include an energy service provider broadcasting a pricing signal, which is then reacted to by the individual DER systems, or a utility multicasting a reduction in generation to all DER systems on a constrained feeder that cannot handle reverse power flows.

These different DER management interactions are shown in Figure 1.

DER System, with Autonomous Behavior

DER Generator

DER Storage

Controller

Controller

DER Energy Management System at Utility Site or

Customer Site

Distributed Energy Resources (DER) Site

One-way Broadcast/Multicast of Mode and/or Schedule

Requests

Loosely-coupled Two-way Interactive

Requests

Tightly-coupled Direct Control


DER Management: Interactions between Components

Loosely-coupled Two-way Interactive

Requests

Utility/ESP DER Management System

Broadcast/Multicast OR

Loosely-coupled Interactive OR


Figure 1: DER management interactionsControl MethodsDifferent control methods can be used. Direct commands provide specific control requirements within the command message. These are typically immediate commands like “turn on” or “limit watt output to xx”.

“Modes” consist of pre-established groups of settings that can enable autonomous DER behavior, where the DER senses local conditions, and, using those mode settings, responds appropriately. This approach minimizes the communications requirements and permits more rapid responses. "Modes" can be established for volt/VAr control, frequency-watt control, charging/discharging storage, and some other complex actions, where the arrays and parameters for each mode are sent ahead of time - maybe once a year or season, and then "go to mode" commands/requests can be broadcast/multicast.

Schedules can also be established, which can operate for a specific time period or indefinitely (once initiated) completely autonomously. For instance, a schedule can establish what modes to use during weekday mornings, versus mid-afternoon, versus weekends.


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Temperature-based curves and pricing-signal curves provides settings for what actions to take based on the current temperature or pricing signal. A pricing signal curve can indicate which mode(s) to go to, based on the pricing signal level (can be $$, but can also be tiers, or H-M-L, or other signal). When a new pricing signal is broadcast, the DERs can ramp to the specified modes. There can even be a schedule of pricing signals so that they do not need to be broadcast, unless an emergency calls for a different level.Ramp rates and parameters based on "% of capability" (rather than absolute amounts) are also included. In addition there is a time-window randomization parameter that requires DERs to respond to commands using a random number within the time window to actually initiate the command. This prevents sharp jumps whenever a new command/request/pricing signal is broadcast. (Obviously the time window can be set to zero if immediate emergency action is required.)

Communication Architectures: Configurations and ProtocolsMany different communication configurations and protocols are possible, with the decisions on which to implement based implementation-specific factors, such as what communication options are available, what the costs involved might be, how much data traffic might be involved, how many DER systems will be included, etc. However, some basic alternative communication configurations (see Error: Reference source not found) include:

Tightly-coupled communications characteristics:

High availability of the communications channel is required since the DER device is dependent on the controller for its behavior.

Strong authentication of all critical interactions is required to ensure only authorized requests and commands are received, such as making settings or issuing control commands.

The bandwidth required would be dependent on the type of DER device, the degree of autonomous behavior that the DER device can handle, and the number of DER devices being managed by the controller.

Many communication configurations are point-to-point, but LANs are also possible.

IEC 61850-7-420 provides object models for the types of information that could be exchanged. These object models can be mapped to different “bits-and-bytes” protocols. A common protocol for tightly-coupled interactions is ModBus, although MMS and web services could also be used.

Often the controllers are bundled with the DER devices: in those cases, the communication protocols may be proprietary.

Loosely-coupled interaction communication characteristics:

Reasonable availability of the communications system is required, but not necessarily as stringent as tightly-coupled communication systems since it is presumed that the DER systems can manage their own behavior. The quality of service would be based on contractual and/or financial requirements for ensuring that DER systems receive the mode requests, the pricing signals, the schedules, and the immediate commands. If communications are lost for any length of time, the DER systems should default to previously-established states.


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Strong authentication of all critical interactions is required to ensure only authorized requests and commands are received. If market-based information or private customer information is exchanged, then confidentiality of the data is also important.

The communication network could be a LAN and/or a WAN. Depending upon the overall configuration, an AMI system could be used for light data traffic, such as direct commands and mode requests, while heavier traffic exchanges, such as establishing the actual mode settings and schedules, could use the Internet.

IEC 61850-7-420 and, more recently, IEC 61850-90-7 can provide the object models for exchanging this information. These object models can be mapped to MMS, web services, DNP3, Smart Energy Profile (SEP), ModBus, and others. Only well-established standards should be used for loosely-coupled interactions to ensure interoperability.

Broadcast and multicast communication characteristics: Reasonable availability is necessary, with the quality of service based on contractual and/or financial

requirements for ensuring that DER systems receive the broadcast/multicast messages. DER systems would manage their own behavior if no messages are received.

Strong authentication of all critical messages is required to ensure only authorized messages are received. Confidentiality would probably not be an appropriate requirement (although not impossible).

The communication network would be a WAN. Possible WANs include AMI systems, utility distribution automation networks, the Internet, cellphone data channels (such as used by Amazon.com for its Kindle), and other types of media.

IEC 61850-7-420 and, more recently, IEC 61850-90-7 can provide the object models for broadcasting/multicasting this information. These object models can be mapped to MMS, web services, DNP3, Smart Energy Profile (SEP), ModBus, and others. Only well-established standards should be used for broadcasts/multicasts to ensure interoperability.


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Utility/ESP DER Management system

DER Energy Management system

DER Energy Management system

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DER Generator

Controller

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DER Generator

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broadcast/multicastLoosely- coupled

two- way interactionTightly- coupled

direct control

DER Management Network Alternative Configurations

Figure 2: DER Management Network Alternative Configurations


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Annex C (Informative) -- Voltage Regulation

Additional operational parameters to consider, when determining the EPS requirements for voltage regulation by DRs. These parameters include the following:

Active and reactive loads due to load-to-voltage dependences. Note that with DR generation embedded in customer’s load, the resultant load-to-voltage dependences are different from the dependences of the natural load [1], [2].

Energy consumption during a prolonged time interval of reduced or increased system voltage

Power flow in distribution and transmission due to change of loads

Losses in distribution and transmission due to changes of power flow and voltages

Total generation due to change of load, losses, and generation capacity according to the capability constraints

Power factors at different buses.

Area EPS Stiffness or Weakness

More information on stiffness (that is also copied from P1547.7 D10.3) is presented earlier in clause 8. P1547.7 D10.35.2.4 System stiffness ratio at the PCC

Power flow studies can document the potential of the DR to impact the Area EPS’s voltage, regardless of the stiffness of the area EPS at the PCC.As introduced in P1547.7 Draft 10.3 clause 4.4.4, “stiffness” is defined as the ability of an Area EPS to resist voltage deviations caused by the DR or loading. For DR interconnections, the stiffness ratio is generally used as an indicator for PCC’s; the lesser the stiffness ratio, the stiffer or stronger, the PCC.IEEE Std 1547.2 defines the stiffness ratio as the relative strength of the Area EPS at the PCC compared with the DR, expressed in terms of the short-circuit kVa of the two systems. The stiffness ratio is calculated at the PCC, unless there is a transformer dedicated to one customer. In this case, the stiffness ratio is calculated on the high-voltage side of the dedicated transformer.

Stiffness ratio = SC kVA (Area EPS) + SC kVA (DR) = SC kVA (Area EPS) + 1 (1) SC kVA (DR) SC kVA (DR)

where

SC kVA (Area EPS) is the short-circuit contribution in kilovolt amperes of the Area EPS (including all other sources)

SC kVA (DR) is the short-circuit contribution in kilovolt amperes of the DR being evaluated

Any individual DR will have some electrical impact on an Area EPS. Everything else equal, a given DR interconnected at a point in the Area EPS where the total impedance is high (e.g., a weak or non-stiff location) will cause greater voltage deviations in the Area EPS. Accordingly,


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there is greater potential for voltage-related impacts from the DR in the Area EPS such as flicker, voltage fluctuations, or changes in steady state voltage.The concept of electrical proximity is related to system stiffness or strength. A DR interconnected at a point in the Area EPS where there is little cumulative impedance from the primary source at the substation may be referred to as electrically close to the substation. A DR connected at such a location is likely to have less voltage-related impacts on the Area EPS.If the DR is small relative to the system stiffness (strength) at the PCC location in the Area EPS, then the potential for Area EPS voltage deviations at the PCC is less. Numerically, a comparison of the power (kVA) rating of the DR with the Area EPS short-circuit kVA at the PCC provides guidance to the DR voltage potential impact on the Area EPSthe higher DR MVA capacity versus Area EPS short-circuit MVA, the weaker the location, and the greater the potential of the DR to impact Area EPS voltage. A simple ratio of the Area EPS short-circuit kVA divided by the kVA rating of the DR may provide a basis for comparison to identify interconnections in weak (non-stiff) locations with the potential for greater voltage-related impacts.

Specifics of voltage regulation meansThe following are the specifics of some current and future voltage and var control means applicable for voltage regulation in distribution:

Transformers with Under-Load Tap Changers (LTC) and voltage regulators with step-wise control. These devices are controlled by voltage controllers following a voltage setpoint (band-center) with a bandwidth. The setpoint can be either a constant value for a given time interval, or can be dependent (typically linearly) on the real and reactive power flow through the monitored element. In the latter case, the controller provides equivalent line voltage drop compensation (LDC).

The bandwidth of the LTC voltage controllers should be greater than the regulation step and the measurement error. The presence of the bandwidth prevents the LTC from “hunting”, but creates an uncertainty in the provision of standard voltages and, therefore, leads to voltage constraints that are stricter than the standard voltage limits. The greater the bandwidth, the higher the probability that the voltage limits will be violated, and the narrower the voltage tolerance should be to avoid the violations. The larger bandwidth also reduces the number of LTC operations caused by voltage and load fluctuations created by DR intermittent operations. Another attribute of the voltage controllers is the time delay, which is also meant for reduction of the excessive LTC operations. The larger the time delay, the higher the probability that the voltage limits will be violated, and the narrower the tolerance should be.

An important consideration with regard to transformers with LTCs is that they typically regulate voltage at a substation bus. Accordingly, transformer LTCs cannot control one feeder’s voltage without affecting the other feeders served from the same substation bus.

Finally, it is worth mentioning that voltage regulators with appropriate controllers support reverse power flow operation. The most common voltage regulator control modes used in distribution applications are as follows [3]:


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a. Locked forward: this control mode is used in locations where forward power flow is expected all the time. The control sets the voltage regulator to its last tap position if reverse power flow exceeding a threshold is experienced.

b. Locked reverse: this control mode is used in locations where reverse power flow is expected all the time. The control sets the voltage regulator to its last tap position if forward power flow exceeding a threshold is experienced.

c. Reverse idle: this control mode is similar to locked forward; the main difference is that it does not allow any voltage regulation operation during the transition from forward to reverse power flow. If the forward power flow falls below a threshold, then the control sets the voltage regulator to its last tap position.

d. Neutral idle: this control mode is similar to reverse idle, the main difference is that if the forward power flow falls below a threshold then the control sets the voltage regulator to neutral position.

e. Bi-directional: this control mode operates the voltage regulator either in the forward or reverse direction until the power flow falls below the respective thresholds. The control sets the voltage regulator to its last tap position during the transition from forward to reverse power flows, and vice versa.

f. Co-generation: this control mode always operates the voltage regulator in the forward direction independently of the power flow direction (forward or reverse).

g. Reactive bi-directional: this control mode is similar to bi-directional, the main difference is that the power flow direction is determined based on the reactive component of the line current. It is worth noting that the power flow direction for the other operation modes is determined on the basis of the active component of the line current.

Shunt capacitors: In North America, shunt capacitors are predominantly used in the medium voltage level (feeder capacitors). They are installed for reactive power compensation in both distribution and transmission systems, providing loss reduction and voltage support, and for reduction of the capacity of EPS facilities. The feeder capacitor banks are typically of one step and are controlled either simultaneously as three-phase devices or as single-phase devices. The sizes of the feeder capacitors are limited by their impact on voltages, including spikes and sags, and by the reactive power flow to be compensated. The number of capacitor operations per day is also limited. Some of the capacitors are permanently connected to the EPS circuit (fixed capacitors), and some are automatically switched ON and OFF dependent on different setpoints of their local controllers, such as time of day, ambient temperature, reactive power flow, power factor, voltage, etc. In the integrated central Volt/var control either the setting of the controllers, or the statuses of capacitors are controlled by the central Volt/var optimization application. Shunt capacitors switched by conventional mechanical switches are not suitable to compensate for voltage changes caused by variable generation.

Shunt reactors: Switchable Shunt reactors may be applied to absorb reactive power, and thus decrease voltage, in order to compensate for voltage rise caused by reverse power flow due to DR.


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Series capacitors: Series capacitors may be used to reduce the total reactance of a distribution line. Their main benefits are to improve voltage profile and reduce voltage fluctuations. [4]. Series capacitors are commonly used to mitigate power quality issues such as voltage fluctuations (flicker) caused by intermittent reactive loads. Series capacitors placed between DRs and the source reduce the total reactance upstream from the DR. It may make it more difficult to compensate for the active power fluctuations due to increased R/X ratio. It must be noted that series capacitors introduce serious concerns related to potential resonance interaction between DRs and the series compensated grids. If the use of series capacitors is considered, the resonance conditions should be analyzed within the possible ranges of operations of DR and grids.

Series reactors: Series reactors may be applied to increase the X/R ratio of a circuit, and thus allow more effective use of dynamic reactive power devices, including certain DR, in order to compensate for voltage variations due to variable real power. This can be particularly useful in circuits with relatively small series reactance. Static Var Controller (SVC) and static synchronous compensators (STATCOM) are fast and continuous means for var and voltage control, typically used in transmission systems. If economically justified, it can be used in distribution to compensate for rapid voltage and var deviations.

Synchronous generators and doubly-fed asynchronous generators: Synchronous generators and doubly-fed asynchronous generators have substantial reactive power capability as defined by the machine’s capability curve (“D curve”). The reactive power is controlled by the machine’s excitation. Automatic voltage regulators are commonly available.

Inverter-based DR: Most inverter-based DR use voltage source inverters which are essentially operating as STATCOM devices as long as their maximum Amp rating is not exceeded by the combination of the real power (kW), reactive power (kvar), and voltage. These devices could actively "try" to correct for voltage deviations outside of some pre-defined band. Providing reactive power increases losses in the DR inverters. Combinations of ramp rate, curtailment, and power factor can be included in control schemes to go way beyond simple power factor scheduling to allow the inverter to very quickly and dynamically control the voltage at its output terminals, if desired by the local Area EPS.

Modes of DR volt/var operations In relation to Volt/var support, the possible modes of operations of conventional distributed generators are as follows5 :

Constant active and reactive power (PQ mode), with or without voltage override

Constant active power and voltage (PV mode).

Detailed discussion on variations of these and other modes of Volt/var control by inverter-based DR are presented in [5]-[8], [1].

5 Under conventional DG we mean here a DG that can keep given active power for a given time interval (schedule), as opposed to renewable DR, in which the active power generation depends on ambient conditions.


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The active power of solar and wind generators cannot be considered constant for any given extended time interval, because it depends on the ambient conditions. Therefore, the PQ and PV modes cannot be applied to these DR. The following modes of local volt/var control can be suggested for such generators:

Constant Q, with or without voltage override

Constant Power Factor (cos φ) at a given location, with or without voltage override

Constant voltage at a given bus.

Curtailed Active Power for voltage limiting

Scheduled reactive power

All these modes of operations of conventional and renewable DR are constrained by the DR capability curves.

While the majority of the utilities currently employ local voltage/var control methodologies (based on local information), a growing number of utilities are implementing Integrated Voltage and Var Control (IVVC) as an advanced DMS application. The local volt/var control is simpler in algorithms and faster in execution, but it is less suitable for integrated (coordinated) voltage and var control, especially with multiple controllable devices, and with dynamically changing operating conditions in all EPS domains pertinent to the volt/var control in distribution. Therefore, for a holistic dynamic optimization of the voltages and vars, a combination of the local controls (primary control) and the centralized control (secondary control) is considered. The central control, based on a wide observation of the Area EPS conditions, adapts the setups of the local controls to the changing operating conditions for the near look-ahead times, while the local controls execute the actual control according to the last setup. The settings determined by the central control application can be issued either for one look-ahead time interval or for several intervals as a schedule. Such a hierarchical integrated volt/var control can provide the most benefits to all EPS domains, as well as to the customer domain.

Illustration of the impact of the X/R ratio on the compensation of the voltage fluctuations caused by fluctuations of the DR kW.Consider a simple circuit diagram (Fig.1). A DR is connected to a low voltage (LV) bus of a distribution transformer. The total impedance between the DR and the source of power consists of the impedances of the distribution transformer, of a portion of the primary feeder (Z-MV), of the substation transformer (Zsub), and of the system equivalent (Zsyst).

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Figure 3. Example circuit diagramCopyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 61

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The changes of voltage due to the changes of Watts and vars can be assessed by using the following formulas:

ΔVoltage Raise /Drop (Watt ) ≈ ΔW × RV

ΔVoltage Raise /Drop ( var ) ≈ Δvar × XV

The sign of ΔW and ∆var defines the sign of the voltage change: If ΔW (Δvar) of DR is positive (generating), it creates a voltage raise, if negative- voltage drop.

Hence, the following equation defines the change of the vars needed to compensate the change of the voltage due to the change of the Watts:

Δvar ≈−ΔW × RX

,

where R and X are the total resistance and reactance between the source of power and the point of constant voltage.

An illustration of the compensation of voltage fluctuations based on the above relationships is presented in Fig. 2 and 3. The first graph represents a case, where the voltage changes along the circuit are caused by a change of a DR kW in the low voltage point and the voltage in this point is compensated by a corresponding change of vars in the same point (LV). The second graph represents a similar situation for a medium voltage point (MV)


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Figure 4. Voltage fluctuations along the OH circuit

As seen in the figures, compensation of voltage fluctuations due to intermittent DR operations by changing the DR reactive power for one point does not completely eliminate the fluctuations in other points of the circuit, because the X/R ratios are different in different portions of the circuit. The uncompensated voltage fluctuations in other points of the UG circuits may be different from the ones in the OH circuits (see Fig. 3).


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Figure 5. Voltage fluctuations along the UG circuit

The X/R ratios are smaller in the under-ground (UG) circuits. Therefore the compensation of the fluctuations caused by the changes of Watts requires greater var changes. Representative example values related to the above illustration are presented in Table 1. As seen in this example, a greater var compensation is needed for the medium voltage level than for the low voltage level, and a greater var compensation is needed for the under-ground circuits than for the over-head ones. Table 1. Required change of DR var to compensate for voltage fluctuations caused by change of Watts, as a portion of Watt change

Primary feeder

Point of constant voltage

MV LVOH -0.30 -0.20UG -0.43 -0.22

With multiple DR or groups of DR located in different places of the Area EPS, the voltage fluctuations in any place of the EPS is a composition of the impacts of all fluctuating DRs, SVCs, capacitors, reactors, etc. Therefore, the different compensating devices should be correspondingly allocated and should operate in a coordinated manner.

Bibliography for Annex C.


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1. Nokhum Markushevich, “Some Considerations of Operations of PV inverters in Electric Power Systems,” Available: http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/TnD/Some_Considerations_of_Operations_of_PV_Inverters_in_Electric_Power_Systems.pdf2. Nokhum Markushevich and Aleksandr Berman, “New Aspects of IVVO in Active Distribution Networks,” presented at IEEE PES Transmission & Distribution Conference & Exposition, 2012

3. F. Katiraei, “Analysis of Voltage Regulation Problem for a 25-kV Distribution Network with Distributed Generation,” in Proc. of IEEE PES 2006 General Meeting, Jul 20064. S. A. Miske, “Considerations for the Application of Series Capacitors to Radial Power Distribution Circuits,” IEEE Transactions on Power Delivery, Vol. 16, No. 2, Apr 20015. “Advanced Power System Management Functions for Inverter-based DER Devices, Draft v.9b”. Available: http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/PvInverter/Advanced_Functions_for_DER_Inverters_v9b.docx

6. B. Seal, “Standard language protocols for photovoltaics and storage grid integration,” EPRI 1020906, Tech. Rep., 2010. Available: http://my.epri.com/portal/server.pt?Abstract id=000000000001020906

7. Petr Sulc, Konstantin Turitsyn, Scott Backhaus, Michael Chertkov, “Options for Control of Reactive Power by Distributed Photovoltaic Generators”. Available: http://arxiv.org/PS_cache/arxiv/pdf/1008/1008.0878v1.pdf

8. E. Liu and J. Bebic, “Distribution system voltage performance analysis for high-penetration photovoltaics,” NREL/SR-581-42298, Tech. Rep., 2008. Available: http://www1.eere.energy.gov/solar/pdfs/42298.pdf


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Annex D (Informative) -- DR Monitoring and Control Concepts

9. IntroductionThe advent of decentralized electric power production is a reality in the majority of the power systems of the world, driven by the need for new types of energy converters to mitigate the heavy reliance on non-renewable fossil fuels, by the increased demand for electrical energy, by the development of new technologies of small power production, by the deregulation of energy markets, and by increasing environmental constraints. These pressures have greatly increased the demand for Distributed Resources (DR) systems which are interconnected with distribution power systems.

Increasing numbers of DR systems are being interconnected to the electric power system (EPS), leading to high penetrations of these variable and often unmanaged sources of power. No longer can they be viewed only as “negative load”. Their unplanned locations, their variable capabilities, and their fluctuating responses to both environmental and power situations make them difficult to manage, particularly as greater efficiency and reliability of the power system is being demanded.

The original content of the IEEE 1547 Parts 1-7 was developed and adopted for scenarios where the penetration level of DR is low. Accordingly, the behaviors described by these parts required that the DR not try to stabilize, regulate, or otherwise influence the power system and that they disconnect quickly when any disturbance is detected.

In the future, these behaviors may be adequate for some situations. However, it is also recognized that communication capability enables re-configuration at the time of install and by commands provided during operation. Through such communications, settings may be changed to enable DR systems to provide a wide range of grid-supportive and value-adding services.

Therefore, DR systems can no longer be viewed as only independent devices that “do their own thing” and force EPS operations to cope with them – they must be capable of actively participating in the management of the EPS both for higher reliability and for increased efficiency. As a result, protective relaying for DR devices, situational awareness by the DR systems, monitoring by utilities, control by DR management systems, and autonomous DR device responses to EPS conditions are becoming increasingly desired, and in some part of the world, mandatory.

This section defines the recommended Monitoring, Information Exchange, and Control (MIC) requirements and capabilities for DR systems, in order for them to appropriately support the power system reliability and efficiency functions for the different EPS scenarios defined in other sections of the 1547.8 document.

9.1 Hierarchical Configurations for DR Management Interaction Processes

Bulk power generation is generally managed directly, one-on-one, by utilities. This approach is not feasible for managing thousands if not millions of DR systems.

DR systems cannot and should not be managed in the same way as bulk power generation. New methods for handling these dispersed sources of generation and storage must be developed, including both new power system functions and new communication capabilities. In particular, the “smart” capabilities of inverter-based DR systems


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must be utilized to allow this power system management to take place at the lowest levels possible, while still being coordinated from region-wide and system-wide utility perspectives.

This “dispersed, but coordinated intelligence” approach permits far greater efficiencies, reliability, and safety through rapid, autonomous DR responses to local conditions, while still allowing the necessary coordination as broader requirements can be addressed through communications on an as-needed basis.

Communications, therefore, play an integral role in managing the power system, but are not expected or capable of continuous monitoring and control. Therefore the role of communications must be modified to reflect this reality.

Inverter-based DR functions range from the simple (turn on/off, limit maximum output) to the quite sophisticated (volt-var control, frequency/watt control, and low-voltage ride-through). They also can utilize varying degrees of autonomous capabilities to help cope with the sophistication.

At least five levels of information exchanges are envisioned. These are described below.

9.1.1 Level 1: Autonomous DR Architecture

Autonomous DR behavior responding to local conditions with controllers focused on direct and rapid monitoring and control of the DR systems: This autonomous behavior would use one or more of the pre-set modes and/or schedules to direct their actions, thus not needing remote communications except occasionally to modify which modes or schedules to use.Figure 6 illustrates a typical architecture that includes PV generation, electric vehicle, battery storage, the owner’s human-machine interface (HMI), and customer load.

Figure 6: Autonomous DR systems at smaller customer and utility sites

Autonomous behaviour is defined as DR systems utilizing pre-set modes and schedules that respond to locally sensed conditions, such as voltage, frequency, and/or temperature, or to broadcast information, such as pricing signals or requests for using specific modes. These pre-settings are updated as needed (not in real-time), possibly through the Internet or through other communication methods.


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The DR systems would utilize its detailed knowledge of the status and capabilities of the DR equipment as well as the status of the local electric power grid, such as voltage and frequency, to determine the output from the DR system.

Common types of autonomous DR systems consist of the controllers that directly manage one or more inverters, such as a small PV system, a battery storage system, an electric vehicle service element (EVSE), and each of the individual DR systems within an office building, a wind farm, or a microgrid.Interaction times are millisecond to seconds.

9.1.2 Level 2: Customer DR Energy Management (CDEMS) Architecture

DR management system interactions with multiple DR systems in which the DR management system has a more global vision of all the DR systems under its control. It understands the overall capabilities of the DR systems under its management but may not have (or need) detailed data.

DR management systems can issue direct commands but they primarily establish the autonomous settings for each DR system. On start-up, the DR management system may provide various possible autonomous mode settings to each of the DR systems, and then over time modify which of these autonomous mode settings are active, possibly in response to utility requests or pricing signals. Common scenarios include a campus DR management system coordinating many DR systems on different buildings or an energy service provider managing disparate DR systems within a community.Additional scenarios include an ISO/RTO managing a large storage device through Automatic Generation Control (AGC) or requesting a specific power factor at the PCC of a wind farm.A microgrid scenario would include a microgrid management system managing the intentional islanding of the microgrid and then coordinating the generation, storage, and load elements to maintain microgrid stability through the combination of setting autonomous modes for some DR systems and issuing direct commands to other DR systems.Interaction frequency may be seconds to minutes, hours, or even weeks.

There may also be a hierarchical set of CDEMSs, such as in a campus where a building CDEMS manages that building, while the campus CDEMS manages all of the building CDEMS. Another hierarchy could include residential CDEMS that are coordinated by a community CDEMS.A CDEMS has a more global vision of the multiple DR systems under its control than each DR controller could have. It understands the overall capabilities of the Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 68

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DR systems under its management and can allocate energy generation and storage functions to each DR system according to the overall energy efficiency and/or reliability requirements.See the blue container in Figure 7.

Figure 7: Customer DR energy management systems (CDEMS) at customer sites and plants

9.1.3 Level 3: Utility, REP, and VPP DR Field Interaction Architecture

Utilities, Retail Energy Providers (REPs) and/or Virtual Power Plant (VPP) operators manage DR systems from a more global perspective, based on the real-time requirements of the distribution and transmission systems, as well as the pricing signals from market systems, rather than only on DR owner preferences. Since the necessary communications from utilities and other energy managers may involve interactions with hundreds and even thousands of DR systems, monitoring their status and output may need to rely on multiple types of solutions. Utilities could monitor the real-time status of DR systems through a combination of:

Directly monitoring energy and other electrical characteristics at the “Point of Common Coupling” (PCC) for larger or more “sensitive” DR installations.


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Receiving aggregated DR data from larger CDEMS systems, such as campuses, office complexes, or industrial plants. This approach can minimize the number of access points monitored.Monitoring energy and other electrical characteristics of a feeder at the distribution substation. This approach is adequate when DR system generation only accounts for a small percentage of the total load on a relatively strong or stiff feeder.

Broadcast/multicast communications consist essentially of one-way notifications without one-to-one communications with large numbers of DR systems. These notifications could be emergency signals, pricing signals, or requests for specific DR modes. Typically these would come from utilities and/or Energy Service Provider (ESP).

No direct responses from the DR systems would be expected. If there were power system changes expected, these would be monitored elsewhere, such as on the feeder or in a substation. If there were financial implications to the broadcast/multicast request, the DR system responses would be determined during the billing and settlements process.These broadcast or multicast requests may be to DR management systems or to individual DR systems.These broadcast/multicast requests would be interpreted by the DR systems as possible modifications of their current autonomous behaviour or could be direct commands for response to emergency situations.Since broadcast/multicast can be used to request actions without necessarily knowing which DR systems can or will respond, the expectation could be that only a certain percentage will respond. Common scenarios include an energy service provider broadcasting a pricing signal, which is then reacted to by the individual DR systems, or a utility multicasting a reduction in generation to all DR systems on a constrained feeder that cannot handle reverse power flows.Broadcast/multicast frequency may be hours, weeks, or seasons.

Because of the large numbers of DR systems, it is expected that broadcast or multicast control commands will be necessary at least for smaller DR installations that are not directly monitored. These broadcast/multicast messages would consist essentially of one-way commands or “requests”, such as emergency commands, demand-response pricing signals, requests for specific DR modes, or providing new schedules. For instance, distribution utilities could issue requests to all DR systems on a feeder to cut back on output to 80% of their current output in order to avoid a reverse power problem. A market-based REP could issue commands to community


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storage systems to start discharging because the price of energy has increased to make it economically beneficial. A VPP could issue new schedules for the DR systems under its control.These hierarchical DR management field interactions are shown in Figure 8.

Figure 8: Utility broadcast DR management system that broadcasts/multicasts commands

9.1.4 Level 4: Utility DR Management Systems (DERMS) for Operations Architecture

Utilities need DR management systems (DERMS) to analyze and coordinate DR systems with distribution operations. DERMS, in conjunction with other distribution operations systems, performs the following functions:

Register the location and capabilities of all DR systems and related CDEMS systems in its territory, following the interconnection process and agreement.


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This information is added to the geographic information system (GIS) for use by other distribution functions.Assess the energy profiles and the ancillary services capabilities of the DR systems for each feeder section and substation. These DR profiles need to be coordinated with the corresponding load profiles, particularly as higher penetrations of DR systems become interconnected to their distribution system. Provide this DR information to distribution management systems to perform contingency analysis, volt-var optimization, and other distribution management functions. Respond to efficiency and reliability requests from the distribution management system by issuing requests for modified DR outputs. Some of the types of management include requesting specific levels of energy output, requesting reactive energy output (vars), requesting low/high voltage ride-through to mitigate possible outages, requesting frequency support, and managing the formation of microgrids.Respond to market pricing information from the demand response system by providing this information to CDEMS systems.Respond to emergency commands from the distribution management system and/or outage management system by broadcasting/multicasting commands to DR and CDEMS systems.

As a result, the utility systems may determine that certain DR systems should either be “commanded” or “requested” (depending upon tariffs and other contracts) to modify their output, such as limiting energy output, providing additional vars, counteracting frequency deviations, or (for EV chargers and storage devices) modifying the rate of charging.Utilities will ultimately need to coordinate many of their systems, including “back office” GIS systems and planning systems, but for the purposes of this architecture, the three main systems consist of the DR Management System, the Distribution Management System, and a “DR SCADA” system that interacts with the DR systems in the field.These types of interactions are shown in Figure 9.


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Figure 9: Utility DR Management System (DERMS) for Distribution Operations Architecture

9.1.5 Level 5: DR Integration with Transmission and Market Operations Architecture

Independent System Operators (ISO) or Regional Transmission Operators (RTOs) and market operations can affect what the DR systems are requested or commanded to do, based on tariffs and other agreements. Therefore, DR operations need to be integrated with the larger grid operations, including transmission and market operations. Distribution utilities must also interact (either directly or indirectly) with their ISO/RTO as a wholesale market participant, and must provide generation and load data to the ISO/RTO in order to meet the NERC Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 73

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reliability requirements. The same types of information must be provided by REPs or other types of energy service providers. These interactions are shown in Figure 10.

Figure 10: DR Integration with Transmission and Market Operations Architecture


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9.2 DR Communication-enabled Capabilities

9.2.1 Advanced DR Functions

DR systems are no longer being viewed as just independently managed systems, capable only of being turned on and off. Particularly those DR systems with inverters can provide a wide range of 4-quadrant functionality that can be used to facilitate the stability and efficiency of the EPS. Some of these are being mandated in European and other countries for this very reason. Therefore, certain of these functions could be required by utilities as part of interconnection agreements including information exchanges to define detailed behavior of and/or manage the functions.These functions, currently defined in IEC 61850-90-7 (an IEC Technical Report that will eventually be included in IEC 61850-7-420 Edition 2) and other supporting documents, include:

Basic monitoring and control:– Reporting of DR status, measurements, nameplate information, and

current settings – Modify inverter-based DR settings that manage power and autonomous

modes – Event logging: access event/history logs to retain a complete report on

DR actions and status– Remote connect/disconnect: connect or disconnect from grid via a switch– Time synchronization: time synchronization across multiple DR systems

Managing DR power settings:– Limit output power: adjust maximum generation level up/down– Set power factor: adjust power factor– Direct charge/discharge management: request real power (charge or

discharge storage)– Pricing signal: request action through a pricing signal

Autonomous modes for power system support:– Volt-var mode: autonomous responses to changing voltage through

modifying vars, based on volt-var curves (see Figure 11)– Frequency-watt modes: autonomous responses to high or low frequency

by modifying the active power, based on frequency-watt curves Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 75

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– Configurable LVRT and HVRT: momentary ride-through for abnormal voltage levels, based on curves defining abnormal voltage levels and durations where DR’s “Must Disconnect” and “Must Remain Connected”

– Dynamic reactive current support: functions defining volt-var support during abnormally high or low voltage levels while still remaining connected, to support low/high voltage ride-through

– Watt-power-factor management: the DR’s power output modifies its power factor, based on watt-power-factor curves

– Voltage-watt modes: autonomous smoothing of voltage deviations by managing the watt output, based on voltage-watt curves

– Voltage-watt storage mode: the storage charging and discharging rate is modified by the local voltage measurements, based on voltage-watt curves

– Temperature-function mode TMP: the ambient temperature smoothly modifies vars so that the DR acts similar to a temperature-triggered capacitor bank, but without the step jumps and harmonics from switching, based on a temperature-var curve

– Pricing signal-function mode PS: a pricing signal is used to indicate what function to execute or what mode to go into

– Peak power limiting: counteract local and/or regional peaks by increasing output during peak situations

– Load/generation following: counteract fluctuations in load or generation by varying DR generation and/or storage output

Figure 11: Example of a volt-var mode curve


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9.2.2 DR Control and Setting Types

The functions would typically be available within the DR systems and activated by local conditions or by external commands. Different DR control and setting types include:

Direct settings and commands provide specific control requirements within the command message. These are typically immediate commands like “turn on” or “limit watt output to xx”.“Modes” consist of pre-established groups of settings that can enable autonomous DR behavior, where the DR senses local conditions, and, using those mode settings, responds appropriately. This approach minimizes the communications requirements and permits more rapid responses. "Modes" can be established for volt/VAr control, frequency-watt control, charging/discharging storage, and other complex actions, where the curve-shape arrays and parameters for each mode can be sent ahead of time - once a year or season for example, and then less informative intensive "go to mode" commands/requests can be broadcast/multicast more frequently in response to specific EPS events. Schedules can also be established, which can operate for a specific time period or indefinitely (once initiated) completely autonomously. For instance, a schedule can establish what modes to use during weekday mornings, versus mid-afternoon, versus weekends. Temperature-based curves and pricing-signal curves provides settings for what actions to take based on the current temperature or pricing signal. A pricing signal curve can indicate which mode(s) to go to, based on the pricing signal level (can be $$, but can also be tiers, or H-M-L, or other signal). When a new pricing signal is broadcast, the DERs can ramp to the specified modes. There can even be a schedule of pricing signals so that they do not need to be broadcast, unless an emergency calls for a different level.Ramp rates, random times within time windows, time delays, and hysteresis to smooth responses across large numbers of uncoordinated DR systems. This prevents sharp jumps whenever a new command/request/pricing signal is broadcast. (Obviously the time window can be set to zero if immediate emergency action is required.)Power settings are based on "% of capability” to avoid the need for absolute values for different DR types, sizes, and capabilities. For example, a utility can issue a request for a 50% increase in available vars, and DERs can respond based on their own capabilities.Protective relaying monitoring and control to ensure safety and anti-islanding.


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9.2.3 Different Types of Information Exchanges for Managing DR Systems

Managing DR systems can range from no monitoring to indirect monitoring to very sophisticated control, with the different requirements dependent on the degree of DR penetration, the DR size, and the weakness of the EPS location. These different management levels can include:

Different levels of protection schemes, including the following– Over-current protection on the area EPS and anti-islanding protection on

the DR– Over-current protection and voltage sensing on the area EPS, anti-

islanding protection on the DR and directional over-current at the DR– Over-current protection and auto ground on the area EPS, directional

over-current on the DR, single line section– Distance or directional over-current protection, auto-grounds, multiple

line sections– Impedance or directional over-current protection and teleprotection

No reconfiguration or communications with DR systems by the utility or ESP. These DR systems are generally pre-set to generate as many watts as possible. This could include off-line registration with the utility to provide DR nameplate information.Pre-set emergency modes of DR behavior based on local conditions (e.g. voltage and frequency) for emergency situations (low voltage ride-through, anti-islanding, extreme high/low frequency deviations). No communications except for off-line registration.Autonomous modes of DR behavior, invoked by utility or ESP requests using broadcast or minimal bandwidth communications (e.g. SCADA or AMI system). The utility monitors the power system (and ultimately the metering information) for the results of these requests. These modes could include arrays of settings for:

– Watt output constraints– Volt-var modes– Frequency-watt modes– Temperature-var modes– Pricing signal-response modes– Low-voltage ride-though modes

Utility direct monitoring at the PCC, including connection status, kW, kvar, & voltage, as is currently recommended in IEEE 1547.


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Site DR management systems monitor and control their DR devices. The control may range from simple (turn off) to more sophisticated (for combined generation-storage systems, specify when and how much to generate and/or store). These DR management systems may be operated by the DR owner or by an ESP.Utility invokes actions and modes through these DR management systems, including turning the DR unit on or off, constraining its power output, or requesting a volt-var mode.Utility schedules actions and modes, based on time-of-day, day-of-week, season, etc.Utility updates mode settings and schedules to reflect changing power system configurations, temporary or maintenance situations, and/or emergency situations. These modes and schedules would then be invoked when necessary. These relatively infrequent updates would require higher bandwidth communications, such as the Internet.Feedback based management, DERs report their status and conditions to management system, which controls or manages DERs based on information received.

9.3 “Sensitivity” of its EPS Environment as Critical to Interconnections

9.3.1 DR System Categorization by the “Sensitivity” of its EPS Environment

With high penetrations of diverse types and capabilities of DR systems, increased communications between grid operators and these DR systems will be required. However, different scenarios and configurations may lead to different types and requirements for these communications. One size does not fit all.Utilities will need to determine the communication requirements by categorizing the DR systems connected to their EPSs based not only according to the individual DR system sizes (as stated in IEEE 1547), but also on the DR capabilities and sensitivity of its EPS “environment” as described in the other sections of 1547.8, including the following four major.

1)Size and capabilities of the DR system itself:– Type of DR unit(s) within the DR system (including aggregations of

different DR devices)– Effective energy (watt-hours) and power (watts) generation of the DR

system at the PCC, assessed relative to the capacity of the circuit. These may be based on ratings or may subtract customer load and demand levels as a contractual statement.


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– Effective kvar– Effective storage capacity: energy (watts-hours) and power (watt) storage

of the DR system at the PCC.– Capabilities to modify watt output or var output, based on local

monitored voltage and/or frequency and/or control commands– Dependency on weather (solar, wind, water) – typical output curves and

intermittency timing and patterns2)Degree of DR penetration (Class Rating), including

– Generation-to-load percentage for the circuit or region– Generation-to-circuit capacity, including the aggregated power relative to

the capacity of the feeding circuit– Correlation between behaviors of relevant DERs, including combinations

of generation and storage (cumulative power)– The correlation between the impacts of different DERs (cumulative

impacts, e.g., on voltages)3)Stiffness or weakness of the EPS location, configuration and characteristics, including:

– Ability of the local grid to handle generation and load fluctuations– Overhead, underground, and/or networked configuration– Potential for voltage imbalances with significant DR– Ability at the substation to handle reverse power flow– Types and capabilities of the equipment on the circuits to manage voltage

and vars.– Safety issues during maintenance

4)Generation and load variability, based on the sizes and capabilities of neighboring DR systems:

– Variability of generation, including fluctuations of renewable energy, availability of compensating generation, storage or load management, and speed of compensation

– Generation and load variability characteristics on the same circuit, on circuits normally connected to the same substation, on reconfigurations of circuits

Additional criteria may affect decisions on communication requirements for specific DR systems, including

Location of the DR PCC with respect to the circuit’s configuration, including:– Phase – Electrical distance of the DERs from sources– Impedances of circuits (e.g., X/R-ratio)


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Requirements of the transmission system for support from the distribution systems

– Potential impact of the DR’s circuit on the transmission system – Emergency operations requirement

The regulatory and financial environment of the utility, including utility economics, energy infrastructure, legacy systems, etc.

– Regulatory requirements for DR system functions– Utility tariff structures– Market pricing structures for energy, demand, ancillary services, critical

peak pricing, etc.Load characteristics

– Type of load– Power requirement– On/off frequencies

9.3.2 Studies for Assessing “DR Environment Sensitivity”

One size cannot fit all situations. The “sensitivity” of the DR’s environment can only be determined by undertaking different types of studies:

The Sensitivity mentioned here is really another consideration for the DR Class rating provided for in Section D2. Each utility can make some basic decision about each DR interconnection just based on the % penetration, DR size and EPS size, with further detailed requirements determined from the list of studies provided below. Most of what is needed to determine a “Sensitivity” is garnered from the immediately available information on the EPS and DR. The additional details that will be used to determine additional requirements will be determined by the studies and contractual requirements.Fault and coordination studies to develop settings to determine which protective relaying scheme is necessary to achieve proper protection coordination.Interconnection impact studies (see IEEE 1547.7) for assessing grid reliabilityMarket assessment studies on the benefits of different DR capabilities to the utility, and the prices that could/should be offered for energy, demand, ancillary services, etc. to DR owners (including the probabilities for percentage of customer participation at different prices).Infrastructure cost assessments associated with providing the infrastructure (communications, cybersecurity, operational analysis functions, and financial


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analysis software for pricing) to make use of those capabilities. These costs could be combined with similar costs for managing other field equipment, including an AMI system, distribution automation, substation management, etc.Future reassessments in which these studies would have to assess this environment not only for the immediate situation but also over time, as additional DR systems are added, as pricing structures change, as customer reactions evolve, and as the grid configurations and equipment are modified.

Therefore, based on the “DR environmental sensitivity” categories, EPS operators can determine the minimum monitoring and control capabilities they would desire and/or require for managing these DR systems as part of managing the reliability and efficiency of the EPS, based on studies such as those recommended in IEEE 1547.7. Table 2 indicates the types of information exchange requirements that may be desired and/or necessary for different characteristics of the power system and size of DR system. Depth of penetration, along with evaluation of DR and EPS sizes is discussed in Annex Z (see Section 2), (need depth of penetration discussion in this guidance document R. Seitz) and could be used to determine a Class rating for the DR installation. A lower Class rated DR installation would have minimal requirements from the EPS while the highest Class rated DR installation would have the most stringent requirements.

9.4 Communication Architectures: Standards, Protocols, and Configurations

Communication standards are critical for interactions with large numbers of disparate types, sizes, brands, and locations of DR systems.

9.4.1 Communication Channel Capability Requirements

Local or wide area (LAN, NAN, WAN) Time latency (ms, seconds, minutes, more) Throughput data volumes (bytes, kbytes, Mbytes) Frequency of interactions (every x ms, seconds, minutes, hours, event

driven) Number of nodes or devices (< 5, <10, < 50, <100, < 1000, > 1000) Availability (> 99.999%, > 98%, < 98%) Cybersecurity (authentication, confidentiality, privacy) Information flow configuration (one-to-one, one-to-many, many-to-many)


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Applicable communication standards (IEC 61850, DNP3, ModBus, BACnet, SEP 2.0, MultiSpeak, IEC 61968, proprietary)

9.4.2 Performance Requirements for Different Types of Information Exchanges with DR Systems

Table 2 provides an assessment of the communication performance requirements for different types of information exchanges with DR systems. It identifies 3 criticality Categories of information exchanges, based primarily on the availability requirements, since high availability is associated with high criticality.It also indicates the cybersecurity requirements and the expected types of configurations. The table also identifies the most likely standard communication object models and protocols that might be used, strictly for informational purposes.


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Table 2: Performance Requirements for Different Types of Information Exchanges with DR Systems

Type of Information Exchange

Communications Network

Time Latency Data Volum

e

Exchange Frequenc

y

Number of Nodes/Device

s

Availability

Cybersecurity Configuration

Semantic Models

Messaging Protocols

Protective relaying

Cat 1

Dedicated media or channel for transfer trip

<8 ms to

<100 ms

bytes Event driven, plus keep-alive

< 5 > 99.999% Authentication One-to-one IEC 61850-7-4

GOOSE, ModBus

Local monitoring (substation / MV / commercial/ industrial. versus LV – residential)

Cat 2

LAN using any media 2 seconds to 10s of seconds

kbytes Every 1 – 60 seconds, event driven

1 to 10s >99.99% Authentication One-to-many IEC 61850-7-420 & -90-7

MMS, web services, ModBus, DNP3, SEP 2, BACnet

Remote monitoring

Cat 2

WAN including the Internet

minutes kbytes Event driven

1 to 1000s >99.99% Authentication, Privacy

One-to-many IEC 61850-7-420 & -90-7

MMS, web services, DNP3, SEP 2

Direct control with responses

Cat 2

LAN or WAN with secured channels (e.g. VPN)

seconds kbytes Event driven


One-to-many IEC 61850-7-420 & -90-7

MMS, web services, ModBus, DNP3, SEP 2, BACnet

Indirect control LAN or WAN with seconds kbytes Event 1 to 1000s >99.99% Authentication One-to-many IEC 61850- MMS, web Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 84

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e

Exchange Frequenc

y


s

Availability


Semantic Models

Messaging Protocols

possibly without responses

Cat 2

secured channels (e.g. VPN)

driven , Privacy 7-420 & -90-7

services, DNP3, SEP 2

Modification of protection (versus other control) settings

Cat 2


seconds

minutes

kbytes Event driven


One-to-many IEC 61850-7-420 & -90-7


Market information

Cat 3

WAN including the Internet

minutes kbytes Hourly, daily

1000s > 90% - 96%

Authentication, confidentiality

One-to-many OpenADR Internet, other public networks

Download of files, reports, event logs

Cat 3

LAN or WAN including the Internet

minutes/ hours

Mbytes Daily, weekly

1 to 10s > 90% Authentication, confidentiality, privacy

One-to-many IEC 61850 Event logs, FTP, COMFEDE


Update software/firmware

Cat 3


minutes/ hours

Mbytes Monthly to yearly

1 to 1000s > 90% Authentication, confidentiality

One-to-many Proprietary Proprietary or public network

Maintenance interactions


seconds/ minutes

kbytes Monthly to yearly

1 to 10s > 90% Authentication, confidentiality

One-to-many Proprietary Proprietary or public network


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e

Exchange Frequenc

y


s

Availability


Semantic Models

Messaging Protocols

Cat 3

Cybersecurity interactions

Cat 3


seconds kbytes Hourly to weekly

1 > 96% Authentication, confidentiality

One-to-one Proprietary Proprietary or public network


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9.4.3 Communication Layers and Models

As discussed in more detail in IEEE 1547.3, communications systems are not monolithic, but consist of different layers. This layering is illustrated in Figure 12 and Figure 13. On the left-hand side is the GWAC stack which is a broad communications model encompassing policies all the way down to basic media connectivity. Next to it is the ISO’s OSI Reference Model which provides more detailed layering within the “bits-and-bytes” layers. On the right are selected communication standards that could be used for information exchanges with or about DR systems. At the bottom of Figure 12 is the IEEE 1547.8 interconnection standard.

Figure 12: Core Smart Grid standards used by utilities


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Figure 13: Customer-focused Smart Grid standards

The IEC 61850 suite of standards defines such a layered communication architecture for power system automation, focused on managing intelligent systems connected with the power system. IEC 61850 as an advanced automation standard is designed to work in distributed computing environments that include those operating in “real-time” where the information exchanges must occur within tightly defined time frames, including less than 4 milliseconds, 10s of milliseconds, seconds, and longer.This IEC 61850 communication architecture consists of standards that define abstract semantic object models of classes (representing hierarchical information models) and syntactic services, such that these object models are independent of specific protocol stacks, implementations, and operating systems. IEC 61850-7-420, IEC 61850-7-4, IEC 61850-90-7, and other related IEC 61850 standards provide data object models for the types of information that would be exchanged with DR systems.The IEC 61850 architecture also includes standards that define the mapping of these abstract object models and services to actual protocol stacks, such as the Manufacturing Message Specification (MMS), GOOSE messaging, DNP3, web services (being updated), and (as a work in progress) SEP 2.0. Additional IEC 61850 technical reports provide guidelines and descriptions on design, Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 88

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implementation, and testing of systems that use the IEC 61850 modeling and mapping standards.The IEC 61850 suite of standards can support all of the needed information exchanges and has the most extensive semantic models for exchanging information with DR systems and for use in protective relaying. Other semantic standards can support exchanging information about DR systems, focused on application-to-application interactions. These semantic standards include IEC 61968 which provides Common Information Models for enterprise information exchanges between applications. The CIM is also being mapped to SEP 2.0 and web services.

9.4.4 Communication Protocols

Communication protocols are the standardized “bits and bytes” that actually transfer data from one system or device to another. The abstract semantic and syntactic object models must be mapped to one of these “bits-and-bytes” protocols in order to transfer data. Examples of these protocols are DNP3, ModBus, BACnet, SEP 2.0, and web services.

9.4.5 Communication Configurations

Many different communication configurations are possible, with the decisions on which to implement based implementation-specific factors, such as what communication options are available locally, what the costs involved might be, how much data traffic might be involved, how many DR systems will be included, etc. However, some basic alternative communication configurations (see Figure 14) include:


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Figure 14: DR Management Network Alternative Configurations


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9.5 Definitions of DR Penetration

Depth of penetration can be categorized as low, medium and high (US DOE Renewable Systems Interconnection Studies)

Low (5%)Medium (10%)High (30-50%)

The depth of penetration can be based on a number of different factors. For each situation the most proper selection of depth of penetration must be made, so that the specific DR is applied most appropriately.

DR connected as a percent of peak load DR energy as a percent of power system energy consumed DR connected as a percent of generation capacity Minimum Load to Generation Ratio(this is the annual minimum load on the relevant power system section divided by the aggregate DG capacity on the power system section)Stiffness Factor (the available utility fault current divided by DG rated output current in the affected area) Fault Ratio Factor (available utility fault current divided by DG fault contribution in the affected area) Ground Source Impedance Ratio (ratio of zero sequence impedance of DG ground source relative to utility

9.6 Different Levels of Communication Requirements

DR of 15kva or less, generally will have low (or very low) penetration on any EPS to which it is connected, and would be considered to be in the lowest rated Class installation. There would also, generally, be neither monitoring nor control required, or even desired between the EPS and DR. At some higher level of penetration, the EPS would need to be apprised of the DR status (on line or off line).There might also be consideration of the impact of the DR in per cent of the averaged annual hourly peak demand (KVA) for the feeder in consideration.I believe this depth of penetration and Class rating of DR should be part of the considerations of other sections of 1547.8 than just the Monitoring and Control. Protective relay selection, active voltage control and other such issues will tie to the size and the impact of the DR involved.


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As the size of DR systems increase, and the Class rating increases, a level of monitoring and/control must be introduced to provide the EPS with more information about the status and condition of the DR. A large DR that still represents a small penetration into the EPS must be considered as representing higher risk of danger than a small DR with the same depth of penetration so additional safeguards through monitoring and control must be considered.

Small size DR, with low penetration will have insignificant effect on either electrical distribution feeder devices or local voltages on adjacent distribution facilities. The small size DR also, cannot support large islands on the primary electrical system.

Much of the concern for the larger DR systems is the greater potential for islanded operation. There is a size at which the DR can alter secondary voltage, but still have no significant influence on primary electrical feeder devices. There will then be greater concern for islanding possibilities.

Further increase in the size of DR can then influence primary feeder devices and operations and cause interference to other EPS customers. More stringent interconnection requirements would then be necessary. Protective relaying, telemetry and control requirements increase as the Class rating of the interconnection increases.


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9.7 Categorizations of Installation Requirements

Table “xx”: Categorizations of DR System Installation Requirements

Penetration

Relative “size”

(impact) of DR

system at the PCC

Communications

Interconnection voltage

Metering via Advanced Metering

Infrastructure (AMI) systems

Interconnection

Disconnect device

Interconnection

Transformer

Protection and Control

Operational Data Logging

Export Power

Control Equipmen

t

Low Penetration

Small DR Voice call or data line at metering

point—Maybe or no

Utility secondary

In/Out Watt-hour

Approved manual

Not required

Approved CB Not required

No

Med DR Voice call or data line at metering

point-Maybe or no

Utility secondary

In/Out Watt-hour

Approved manual

Not required


Large DR Voice call or data line at metering

point

Utility secondary

In/Out Watt-hour

Approved manual

Not required


Maybe Contractua

l Requireme


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Penetration

Relative “size”

(impact) of DR

system at the PCC

Communications




Interconnection

Disconnect device

Interconnection

Transformer



Export Power

Control Equipmen

t

nts

Moderate Penetration

Small DR Voice call or data line at metering

point-Power Quality maybe

TBD In/Out Watt-hour

Approved manual

Maybe Approved CB Maybe Yes

Med DR Voice call or data line at metering

point—Power Quality-maybe

TBD In/Out Watt-hour

Approved manual

Maybe Approved CB Maybe Yes

Large DR TBD Distribution secondary or

primary

In/Out Watt-hour

(reactive metering, reactive demand

Approved manual

Required Approved CB 7 day digital data

logger

Yes


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Penetration

Relative “size”

(impact) of DR

system at the PCC

Communications




Interconnection

Disconnect device

Interconnection

Transformer



Export Power

Control Equipmen

t

metering or time of deliver)

High Penetration

Small DR Continuous telemetry

Distribution secondary or

primary

OK In/Out Watt-hour


metering or time of deliver

Approved manual Required Approved CB 7 day

digital data

logger

Yes

Med DR Continuous telemetry

Distribution Primary

OK In/Out Watt-hour


metering or

Approved manual Required Approved CB 7 day

digital data

logger

Yes


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Penetration

Relative “size”

(impact) of DR

system at the PCC

Communications




Interconnection

Disconnect device

Interconnection

Transformer



Export Power

Control Equipmen

t

time of deliver

Large DR Continuous telemetry

Distribution Primary

Yes In/Out Watt-hour


metering or time of deliver

Approved manual

Approved CB 7 day digital data

logger

Yes


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9.8 Considerations for each Class rating should include

Minimum requirements for Class “xx” facilitiesDoes the installation meet the criteria for this Class installation?What portion of DR capacity will be consumed at location and what portion will be exported?Can DR interconnection be made at specified voltages for that Class?

Metering requirements for Class “xx” facilitiesAll Class of installation will require bidirectional or “in/out “watt –hr metering.Higher Class installation may have additional requirements (that depend on specific contractual agreements) such as:

– Generator output metering– Reactive power energy metering (VAr-hour)– Real or reactive power demand metering– Time of delivery metering

Interconnection Disconnect Device for Class “xx” facilitiesSome means of manual disconnect will be required by the utility.

Interconnection Transformer for Class “xx” facilitiesClass of installation, utility distribution voltage, power quality considerations , etc. will determine if an interconnection transformer is necessary.

Protection and Control Devices for Class “xx” facilitiesParalleling device

For small Class Rated DR that use PV and Wind converters the following features are generally included in the Approved converter equipment used.

Over/Under Voltage ProtectionOver/Under Frequency ProtectionSynchronizing Protection Ground Fault ProtectionPhase Fault ProtectionTransfer Trip Protection

Automatic Synchronizer along with Sync check relay(25) will be necessary with synchronous and similar generators.Speed matching relaying will be required with induction generators.Telemetry and Monitoring for Class “xx” facilities


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Communication will require telephone or other voice communication for contact with DR responsible party, for larger Class rated DR, but may not be necessary for the smallest Class rated DT. Where telemetry is required the following data and measurements should be considered as minimum for telemetry

– Energy Flows (kWh)– Real Power Flows(kW)– Reactive Power Flows (kVAr)– Voltage at PCC– Parallel device status.– Monitoring

Where there is a potential that the DR output can adversely affect the standard performance of the utility or the quality of power delivered to its consumers the following monitoring may be required to detect and record disturbances:

– Waveform distortions– Electrical Noise– Voltage sags or swells– Frequency deviations– Harmonic distortions

Operation Data Logging for Class “xx” facilitiesWhere data logging is required the following should be considered as minimum for recording:

– Volts– Watts, VArs– Frequency,– Status of key system elements– Time Stamp

Export Power Control EquipmentMay be required. Often necessary for larger Class rated DR

– Voltage Regulator/Power Factor Controller– Direct Digital Control– Power system Stabilizer

And in all this there are Anti-islanding or intentional islanding considerations as well as grounding techniques.


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Annex E (Informative) -- Group Behavior

Knowledge base for CVRCVR is a mode of operation in power distribution systems with the objective of reducing the energy consumption (including T&D losses) by reducing the voltages applied to the end-user appliances.

This mode of operations may be available only within the standard voltage limits. However, the tolerances for this mode of operations may be additionally limited by the voltage sag or voltage variability within the Area EPS. A group of DR connected to common circuits and participating in an EPS voltage regulation scheme may reduce voltage sag and voltage variability and provide flatter voltage profiles. The reactive power capability of DR may provide reactive power compensation sources that are more distributed, more flexible, and more dynamic than conventional capacitors, or may be in network locations where capacitors are difficult to place.

On the other hand, a group of DR connected to a common circuit can also have adverse impacts on Conservation Voltage Reduction due to the following:

DR can increase voltages in a portion of feeder, preventing from reaching the lowest voltage limit Uneven siting of DR by phases, can increase voltage imbalance, which can result in reduced CVR benefits Intermittent operations of DR if not compensated may increase voltage fluctuations introducing uncertainty in the

volt/var control, which would lead to reduction of operational voltage tolerances and reduced benefits of CVR. Fluctuation of DR active and reactive powers and circuit voltages can lead to excessive operations of other EPS

volt/var controlling devices. To prevent the excessive operations, these devices can be made less sensitive to the changing operating conditions, which would either reduce the CVR benefits, or require installation of additional continuous volt/var controlling devices in the EPS.

Absorbing reactive power by DR to reduce the voltage fluctuations caused by intermittent generation of active power would increase the reactive power flow in the circuits and either increase losses, or require installation of additional var-compensating devices in the EPS

The CVR mode of operations and its benefits are based on the active and reactive load to voltage sensitivities. [1]

The dominant sensitivities of the loads to voltage are positive: an increase in voltage applied to the end-user appliances results in increase of the loads. This factor is used in a short-term fashion for peak load reduction by temporary reduction of voltages within given tolerances. If the voltage reduction is applied in a long-term manner, and the load dependency on voltage is still positive, the accumulated load reduction results in reduction of the consumption. The load-to-voltage sensitivities are different for short-term and for long-term applications. Typically, the sensitivities for the long-term applications are smaller.

It has become common to define the consumption sensitivity to the voltage by the Conservation Voltage Reduction factors (CVRf) separate for the active load and for the reactive load (CVR-watts and CVR-vars). The CVR-watts factors are measured in percentage change of consumption per percent change in voltage. The CVR-vars factor is measured in percentage change of average vars (or kvarh) during a long-term interval per percent of voltage. Typically, the CVR-vars are greater than the CVR-watts. It must be noted that the presence of embedded DRs in customer loads changes the CVR factors as the EPS sees it. The impacts of DRs on the CVR factors are different depending on the mode of operations of the DR, its capability curve, and control settings [2], [3].

Coordination of Groups of DRAs stated in Clause 4 a DR may not regulate EPS voltage at the PCC per se, as the responsibility for EPS voltage regulation lies with the EPS operator (per IEEE 1547-2003). However, DRs may actively participate in EPS Volt-VAr


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management schemes, including a Volt-VAr management scheme to support CVR. The CVR mode of operations implies the usage of direct voltage-controlling devices, such as transformers and voltage regulators with load tap changers (LTCs), switched capacitors, DR with var-controlling capabilities, and other volt/var controlling devices. In addition to the voltage, the operations of all these devices impact the power flows and losses in distribution and transmission, as well as other critical parameters depending on the specifics of the EPS. All these factors should be taken into account, when optimizing the volt/var control in distribution with the CVR objective. When multiple DRs are connected to a common distribution circuit, the resultant operating conditions of the circuit depend on the combined impact of the group behavior of the DRs. The CVR optimization is limited by the lower voltage limits in a number of voltage-critical points. If DR or Demand Response exist in these points and their kW and/or kvar can be controlled to reduce the voltage drop between the power source and the subject point, it would release more room for CVR and provide more benefits. The impact of such DRs on the operations of the EPS would provide much greater benefits [4, 5]. As it was mentioned above, in some situations some DRs may have an adverse impact on the benefits of CVR. Therefore, in order to achieve the optimal CVR results the operations of the DR in the group should be coordinated. As it follows from the above, conducting the CVR mode of operations in a comprehensive manner is a highly sophisticated endeavor, and it can be implemented best as an advanced Distribution Management System (DMS) application [6]-[8].

Value of BenefitsIn principal, CVR as a sustained mode of operation could reduce energy generation required to serve EPS load by 1-2%, for a very significant resulting benefit. A number of studies and implementations of CVR were performed. These studies addressed the current benefits of CVR, which consist of reduction of energy generation, meaning reduction of the sum of consumption and losses. However, there are aspects related to CVR, which were not sufficiently addressed. For instance, there is a concern that under lower voltages the end-use appliances are more exposed to critical voltage sags [9], which may be unacceptable by some sensitive users.

Also, while lower voltages (within reasonable limits) in most cases result in lower consumption, they also result in reducing the useful output of many devices. In the cases of oversized appliances, it is unlikely that the users would react. However, in the cases of undersized appliances the user may adjust to the permanently lower voltage by increasing the capacity of appliances, which may increase the consumption in long run.

CostThe cost involved in CVR includes the incremental cost of the voltage-regulating abilities of DR. DR may significantly contribute to the benefits of CVR by lowering the voltage drops along the distribution circuits, especially if they are located in the voltage-critical points. Sometimes, for the EPS to benefit more from CVR, additional investment in the DR may be needed (e.g., the ability to generate and absorb a certain amount of reactive power, or be available for active power control, etc.). The cost also includes the cost of communications, software and hardware, and O&M supporting the CVR mode of operations. There may also be costs associated with enhanced monitoring and controls for other EPS voltage controlling devices such as LTCs and switched capacitors.

Misconceptions related to CVRWhen considering implementation of CVR, the following common assumptions about distribution system operations should be revisited [10]: Assumption: The lowest voltage is always in the end of the feeder. This notion is often misleading,

especially in the cases with capacitors and DR connected along the feeder. It is important to emphasize that the voltage quality limits, within which the CVR should perform, are assigned to the end-user service terminals, which is predominantly in the secondary distribution. The voltages in the primary distribution are often not indicative of the voltage quality at the service terminals due to different loading and impedances of the distribution transformers and different characteristics of the secondaries between the distribution transformers and the service terminals.

Assumption: Power factor equals one is always good. In many cases, to support


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PF=1 in the distribution system elements, either additional reactive power should be generated by reactive resources, or the reactive power should not be absorbed. However, generating or not absorbing reactive power results in voltage increase, unless the increase is compensated by other voltage-controlling means. The increase of voltage leads to an increase of consumptions and reactive load and to a reduced the power factor at the customer side. If this increase of consumption exceeds the reduction of losses due to higher power factor in the primaries, there will be an increase in the needed generation instead of conservation [11], [12].

Assumption: Load (energy) reduction due to voltage reduction also means current reduction. The kW and kvar reductions due to voltage reduction imply current reduction, while the voltage reduction by itself leads to the current increase. The resultant change in current depends on the relationships between these two impacts, which are defined by the CVRf and PF of the power flows through the subject element [13], [12]. For instance, if CVRWatts = 0.7, CVRvars=3, and PF = 0.95, the CVRAmps= - 0.079; and if PF=0.98, then CVRAmps= - 0.212. (Negative CVR means increase of Amps with the decrease of voltage)

Assumption: The setup of the conservation volt/var optimization is strictly limited by the standard voltage quality limits. In general, this is a true assumption. However, there are factors to consider when determining the practical limits for this optimization. There is always an uncertainty in the result of execution of the optimal solution. This uncertainty is caused by the bandwidths of the voltage- and var- controlling devices, by the inaccuracy of voltage measurements and underlying models used for the optimization, by the unknown voltage imbalances in different points, etc. Due to these random factors, the tolerances for voltage optimization with the CVR objective should be reduced in comparison with the standard tolerances.

Also, there may be highly sensitive end-users which need narrower than standard voltage tolerances at their service terminals at all times, or at specific times. If such agreement between the customers and the EPS is negotiated, the limiting the CVR voltage tolerances may be different at different service terminals and at different times.

Assumption: Near-real time measurements from Smart Meters provide all the information needed to control voltage and vars. CVR optimization is limited by the lower voltage limits in the voltage-critical points which are not the same all the times. They move along the distribution circuits depending on load composition, operation of capacitors and DRs, and circuit connectivity. Even if the measurements from the Smart Meter in the changing critical points were practically available, they would not provide sufficient and reliable information for the complex CVR optimization, which involves a multitude of controlling devices and impacts a large number of operational parameters in different domains of the power system. The measurements from the Smart Meters do not provide information for the ”what if” studies, which, essentially, are the basis for the optimization. However, the data collected from the Smart Meters over a period of time, including the measurements of kW, kvar profiles, along with the voltages, is a rich source of information for development of adequate behavioral models needed for a comprehensive CVR optimization [14], [16]. These measurements can be also used for periodic validations of the operation models used for CVR.


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A big unknown aspect of DR involvement in CVR is the reconciliation of the operations of DR under steady-state and intermittent conditions. (See more on this issue in Clause 1547.8 – for 1547-2003. 4.1.1). Further studies on CVR to address these and other issues are needed.

Bibliography for Annex E

1. Nokhum Markushevich, Aleksandr Bermanand Ron Nielsen, “Methodologies for Assessment of Actual Field Results of Distribution Voltage and Var Optimization,” presented at IEEE PES Transmission & Distribution Conference & Exposition, 20122. Nokhum Markushevich, “Some Considerations of Operations of PV inverters in Electric Power Systems,” Available: http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/TnD/Some_Considerations_of_Operations_of_PV_Inverters_in_Electric_Power_Systems.pdf3. Nokhum Markushevich and Aleksandr Berman, “New Aspects of IVVO in Active Distribution Networks,” presented at IEEE PES Transmission & Distribution Conference & Exposition, 20124. N. Markushevich and A. Berman, “Distribution Automation and Demand Response,” Transmission & Distribution, 2008, Volume 20, No. 8 ; 2009, Volume 21, No. 1 http://www.electricity-today.com/download/issue8_2008.pdf; http://www.electricity-today.com/download/issue1_2009.pdf5. Nokhum Markushevich and Edward Chan, “Integrated Voltage, Var Control and Demand Response in Distribution Systems,” Presented at IEEE PES Power System Conference and Exposition, March 2009, Seattle6. Report to NIST on the Smart Grid Interoperability Standards Roadmap, June 2009; http://nist.gov/smartgrid/InterimSmartGridRoadmapNISTRestructure.pdf7. Distribution Grid Management (Advanced Distribution Automation) Functions. Use Case Description, submitted to the SGIP DEWG, PAP8, 2/2010. Available: http://collaborate.nist.gov/twiki-sggrid/pub/SmartGrid/PAP08DistrObjMultispeak/Distribution_Grid_ManagementSG_UC_nm.doc8. Nokhum Markushevich, “Applications of Advanced Distribution Automation in the Smart Grid Environment,”T&D Online Magazine, January-February 2010 issue. Available: http://www.electricenergyonline.com/?page=mag_archives9. NIST reviews impact of conservation voltage reduction for electric power industry. Available: http://findarticles.com/p/articles/mi_m0IKZ/is_2_107/ai_87701396/10. Nokhum Markushevich, “The Benefits and Challenges of the Integrated Volt/Var Optimization in the Smart Grid Environment,” Presented at IEEE PES General Meeting, 2011, Detroit11. Nokhum Markushevich, “Understanding Coordinated Voltage and Var Control in Distribution Systems: Is Power Factor = 1 Always a Good Thing?,” Energy Pulse, 2007, http://www.energypulse.net/centers/article/article_display.cfm?a_id=155312. IntelliGrid Architecture Development for Distribution Systems: Requirements and Device Information Models for Integrated Advanced Distribution Automation Applications. EPRI, Palo Alto, CA: 2008. 1013843. Available: http://www.epri.com/search/Pages/results.aspx?k=101384313. Nokhum S. Markushevich, “The Specifics Of Coordinated Real-Time Voltage And Var Control In Distribution,” Distributech Conference, 200214. Benefits of Utilizing Advanced Metering Provided Information Support and Control Capabilities in Distribution Automation Applications, EPRI Product ID 1018984, Technical Update,: December 200915. Nokhum Markushevich and Wenpeng Luan, Achieving Greater VVO Benefits through AMI Implementation, Presented at IEEE PES General Meeting, 2011, Detroit16. Implementing Distribution Performance Optimization Functions that Integrate with Advanced Metering: AMI for Volt/Var Optimization. EPRI, Palo Alto, CA: 2010 1020091. Available: http://www.epri.com/search/Pages/results.aspx?k=1020091


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Annex F (Informative) -- DR and Utility Protection Best Practices

Introduction

This Annex focuses exclusively on issues associated with protection when connecting DR to the electrical grid.With reference to 1547, this deals specifically with clauses 4.2.1 and 4.2.2. See below.

4.2 Response to Area EPS abnormal conditionsAbnormal conditions can arise on the Area EPS that require a response from the connected DR. This response contributes to the safety of utility maintenance personnel and the general public, as well as the avoidance of damage to connected equipment, including the DR. All voltage and frequency parameters specified in these sub clauses shall be met at the PCC, unless otherwise stated.

4.2.1 Area EPS faultsThe DR shall cease to energize the Area EPS circuit to which it is connected prior to recloser by the Area EPS.

One of the concerns is the question of whether the DR must be able to detect faults on the Area EPS. 1547.2 Section A.1.4 state

“The interconnection system must be able to detect faults in the area EPS and isolate the DR. Although the requirement in the standard is absolute in its wording, it is recognized that it is possible to have faults of various types that do not cause significant variation in the current flow, voltage, or frequency sensed at the PCC. As a practical matter, if a fault is too distant from the PCC or too minor to be sensed reliably at the PCC, there is no technical reason to isolate the DR.”

Based on the statements in sections 4.2.1 and 4.2.2 of 1547, it is not logically necessary to detect faults or to isolate the DR. 4.2.1 and 4.2.2 only require the DR to cease to energize for faults. 4.2.1 and 4.2.2 allow a scheme that uses transfer trip from a detector at the utility, and a scheme that uses a detector at the utility to open the utility connection and an anti-islanding protection at the DR to isolate the DR. Also, 4.2.1 and 4.2.1 only require the DR to cease to energize, which is not necessarily the same as isolating the DR. For example the low side breaker at the DR could be opened isolating only the generator part of the DR. Thus A.1.4 of 1547.2 does not agree with 1547.


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The selection of an appropriate protection solution follows the information provided in a fault study and load study as per 1547.7. These studies will provide the information required to select the protection solution that best co-ordinates the DR with the EPS.

From the perspective of protection of the Area EPS and the DR, high penetration can be defined as the point at which the amount, location, or type of DR results in modifications to the Area EPS. When DR penetration is low there is no requirement to modify the Area EPS but as the amount, location and type of generation connected to the area EPS is modified, the results of the 1547.7 studies will demonstrate the necessity to revise the Area EPS.

To meet the requirements of 4.2.1 and 4.2.2, it is first necessary to examine current practice, what exists now in the suite of 1547.x documents, and establish where the gaps are. Our task is to develop protection alternatives for the DR to be able to detect faults on the Area EPS. However, during this exercise of preparing this document, three key points have emerged:

1. It is necessary to consider the entire protection system not just the protection system at the DR. With very low penetration, there is little or no impact on the functionality of the Area EPS protection system and the two protection systems may be designed independently. As the level of penetration increases, this is no longer the case. The DR protection and the Area EPS protection must function as a unit.

2. A protection system that functions as a unit will consist of one or more fault detectors at the DR, one or more fault detectors at the Areas EPS, isolating devices and in some cases, protection communication channels for functions such as transfer trip.

3. It is important to distinguish between fault detection schemes and anti-islanding schemes. A properly designed line (feeder) protection scheme at the DR will employ fault detection techniques that detect the fault and disconnect the DR. Anti-islanding schemes are designed to detect the island condition when there is no fault. DR protections that rely solely on anti-islanding techniques present a higher risk of power quality problems for customers in the island and a higher risk of an out-of-phase reclose. It is our current opinion that reliance on anti-islanding schemes as the main line of defense is not preferred yet but in some applications may not be avoidable. This document will focus on line protections and not anti-islanding protections except insofar as reliance on anti-islanding schemes may be the only practical means of meeting the requirements of IEEE 1547 section 4.2 for certain types of DR, such as single phase connections.

IEEE 1547 sections 4.2.1 and 4.2.2 requires Distributed Resources (DR) interconnecting with an Area Electrical Power System (EPS) to disconnect from a faulted EPS and to do so prior to the utility’s re-energization of the EPS. Six general issues affecting this requirement which must be addressed are discussed below.

Dual function of the Interconnection Circuit BreakerThe interconnection circuit breaker must open for faults on the EPS side fed by the DR and for faults on the DR side fed by the EPS. Since the two fault levels might be very different, simple non-directional overcurrent protection may be insufficient. Directional sensing may be required. The interrupting ratings must be adequate for the worst of the two cases.

Tripping for Faults on Adjacent FeedersWith the addition of the DR to a feeder, an EPS fault on an adjacent circuit to which the DR is connected may unnecessarily trip the circuit to which the DR is connected Coordination to prevent


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this may be achieved by proper choice of settings, time delayed tripping or, if necessary, directional features including pilot schemes such as Directional Comparison Blocking (DCB).

DesensitizationThe fact that both the utility and the DR will feed faults at various locations on the circuit may cause each of these sources to see a lower fault current than they would if they alone were feeding the fault depending on the fault location with respect to the DR. This can lead to slower tripping and even failures to trip. This occurs for all fault types but can be more acute on ground faults. Meanwhile, the fault location may experience more fault current than would be the case with only one source.

Non-directional Reclosers and Islanding a DR is downstream of a recloser, and a fault occurs upstream of the recloser, fault current from the DR may trip the recloser, creating an island downstream of the recloser supplied by the DR. Preventing this may require the addition of directionality to the recloser.

Fast vs. Slow Reclosing Utility PracticeIEEE 1547 requires anti-islanding features of DR to operate within 2 seconds. If the utility recloses faster than this, paragraph 4.2.2 of the Standard may be violated and an out of synchronism parallel may occur. Some inverter technology may be able to tolerate this without ill effect. Synchronous machines and other inverters may not. Several ways of dealing with this under consideration include:

Line protection to trip the DR for all faults on the feeder to which the DR is connected before the reclose occurs

Not reclosing until after 2 seconds Supervising the reclosure with a voltage check, zero volt permission to reclose Using a grounding switch to force DR off prior to reclosing Slow speed transfer trip Rate if Change of Frequency protection at the PCC or DR Traditional high speed transfer trip

Single Phase DRSingle phase DR may not be able to detect single phase faults on the EPS. This requires either transfer trip or reliance on the anti-islanding feature of the DR, i.e. Rate of Change of Frequency (ROCOF) at the PCC or DR Emerging requirements for DR to actively participate in Volt/VAR and Frequency/Watt management may be in conflict with passive and active anti-islanding schemes.

2.0 EPS Fault Types

2.1 High Resistance FaultsThe detection of high resistance faults has always been a problem for four wire distribution systems. There is no technology on the market today that can guarantee detection in all cases. This problem is not unique to the DR. The utility has the same problem when the DR is disconnected. The two most popular approaches in use today are:

1. Use a standard value of resistance to represent the high resistance fault. The most widely used value is 40 ohms.

2. Put a margin on the set point to allow for the fault resistance. For example, the setting for a phase-ground fault may be set assuming the fault current will be 50% of the minimum in feed with a fault Z of zero.


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To not place undue hardship on the DR proponent, it is recommended that the proponent be required to design the DR protection to be as sensitive as the Area EPS protection.

2.2 Open Phase FaultsOpen phase faults are not normally part of distribution protection systems. These may be detected by the DR protection system and/or the EPS protection system due to unbalanced currents or voltage. It is not considered necessary to make detection of these faults a requirement.

2.3 Faults During Normal System OperationThe DR protection system shall be able to detect faults on the Area EPS with no other generation connected, all other generation connected but operating at minimum generation, all the generation at maximum generation, and all the other generation and the utility disconnected. The short circuit analysis data needed for proper selection and setting of the selected protection shall be available to the DR owner and the EPS owner and operator as per IEEE 1547.7 (C2.1 Short Circuit Analysis). If additional DR is connected new studies may have to be performed.

2.4 Faults on the Transmission SystemFaults on the transmission system that supplies the distribution system substation may result in the DR feeding the fault through the substation transformer. Even with a failed feeder circuit breaker, the Area EPS protection is expected to clear the fault. Therefore, the DR protection is not required to detect these faults.

3.0 Distribution Systems and the Connection of DRThe DR may be connected to a three phase three wire uni-ground distribution system or a three phase four wire multi-grounded distribution system. The protection options discussed below may be applied on both systems. There are a small number of ungrounded systems in use in North America. These are not being considered in this document. For a discussion on the design and operating practices for North American distribution systems refer to Annex G.

There are a number of issues that must be considered when connecting DRs to the distribution system including the impact on the Area EPS protection system and Temporary Over Voltages (TOV). For a discussion on these topics refer to Annex H.

4.0 General Requirements for ProtectionThe following is a list of general minimum requirements that are related to protection. It is not meant to be an exhaustive list and there are other issues that are important when designing a protection system.

4.1 DR Transformer ConnectionsThe transformer connection for three phase systems has a significant impact on the utility protection and the DR protection. The utility typically provides the DR proponent with a list of acceptable connections for their three wire and four wires systems. See Annex 1 for a discussion on this topic.

4.2 Protection DC SupplyFor systems that rely on a battery for operation of the protective relay and/or the operation of the isolating device, the battery charger will be equipped with monitoring and alarms to alert the utility and/or the DR owner of a failure. The DC battery voltage shall be separately monitored. The DR shall be automatically disconnected from the grid prior to the battery voltage decreasing to a level where the


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protective relay or the isolating device may fail to operate.

4.3Total Fault Clearing TimeThe DR total fault clearing time must coordinate with the Area EPS protection and control system including the reclosing. The total fault clearing time will include the fault detection time, the operation of any interposing or auxiliary relays, and the fault current interruption time of the isolating device. Typical values for fault detection with modern protective relays are in the range of 25 ms and modern circuit breakers interrupt the fault in less than 100 ms.

Distribution systems normally are not designed with duplicate protections or breaker failure protections. However, they are designed with a backup protection which operates when the first upstream isolating device fails. This is normally accomplished through the application of inverse time overcurrent devices. The upstream device is set to clear the fault if the downstream device fails. This of course will result in a longer clearing time. For the DR protection system to be based on the same design principle, there must be a backup isolating device if the main device fails. Many smaller installations have a supply transformer that is protected by fuses. The fuses are selected on the basis of protecting the transformer for a low side fault. These fuses may be able to protect the utility system for a fault on the utility system if the DR circuit breaker fails to operate. If not, a second isolating device is required. For example, this could be a second circuit breaker on the low voltage side of the transformer or a circuit breaker on the Area EPS side of the transformer.

4.4 Communications RequirementsCommunication is required between the DR and the utility, and between the utility substation and a recloser for one of the protection proposal presented below. Communication is also required for other functions.

4.4.1 Protection ChannelsOne of the protection options described below requires communication for protection purposes. This is for a pilot scheme such as Directional Comparison Blocking (DCB) and or Transfer Trip (TT). The protection scheme must be designed to accommodate the total channel time, defining the total channel time as the time a closed contact on the transmitting end is detected as a closed contact at the receiving end. As the maximum time is reduced, the cost of providing this function often goes up exponentially. Channel times in the order of 2-3 cycles are required on transmission protection systems for system stability. This is not an issue for distribution systems to date. It is possible that this may become a concern if large amounts of DR are deployed. The maximum acceptable channel time for distribution system protection needs to be specified.

When a protection system utilizes communication in its design, this essentially means that if the channel fails to the DR, the DR must be taken out of service. If the utility protection system is designed to rely on communications and the channel fails, that could also mean the line section must be taken out of service interrupting customers. To avoid this situation, the protection system should be designed to be able to accept this contingency or be designed with main and alternate channels.

4.4.2 SCADA ChannelsMost utilities are requiring that DRs above a particular size be equipped with SCADA back to the Area EPS control center for monitoring only, or for monitoring and control. The selection of the size of DR appears to be arbitrary and varies from one utility to the next.


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4.4.3 Remote Maintenance and Engineering Access All the Intelligent Electronic Devices (IEDs) on the market today have extensive monitoring capabilities. This includes data loggers for load profiling, oscillography, sequence of events reports and fault reports. These records are vital in troubleshooting protection problems as well as verifying that a particular scheme is functioning as intended. Real time access is also desirable for troubleshooting. Many DRs and utility reclosers are located several miles away from the work centre of the utility. Often the DR owner is relying on a consultant for support who may be located thousands of miles away. Remote access to the IEDs solves this problem. Unfortunately, it introduces a new one, security. The most economical method of establishing remote access is via the Internet. By using Virtual Private Networks over the Internet, a high level of security is possible. .

5.0 Protection OptionsThe protection options should have the following attributes:

The DR protection must be able to detect all faults on the Area EPS with all levels of generation from minimum to maximum and de-energize the circuit to which it is connected.

The DR protection must de-energize the circuit to which is connected prior to the Area EPS reclosing.

The Area ESPS protection must be able to detect all faults on the Area EPS with all levels of generation from minimum to maximum and de-energize the circuit.

Address both the Area EPS and DR interconnection requirements. Be cost effective. Be scalable from one option to the next. Cover all conceivable levels of penetration. The protection solution for the DR connection should not adversely impact the power system

reliability.

The protection options described herein are suitable for both three wire and four wire distribution systems. Option 1 is the status quo where options 2 through 5 are new proposals. To select the best option, one would begin with the least expensive alternative, perform a fault and coordination study, and attempt to develop settings to determine if proper protection coordination can be achieved. If not, then it would be necessary to move up to next level of complexity and expense. The five options will cover the range from low penetration to high penetration and from small DRs to large DRs.

The selection of the correct option shall address all protection issues uncovered by the system study. These include but are not limited to:

Prevention of false tripping of healthy feeders with the addition of the DR for faults on adjacent feeders

Prevention of unacceptable levels of blinding or desensitizing the existing protections when the DR feeds fault current into a local fault.

Prevention of unintended islanding, through tripping of a feeder recloser or main circuit breaker, which can lead to blocking of auto reclosing, an unsynchronized reclose or removal of ground sources.

Ensuring proper protection at the PCC such that the interconnection protection is selective for both faults on the area EPS and faults within the DR site.


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5.1 Option 1-Overcurrent Protection on the Area EPS and Anti-islanding Protection on the DRRefer to Figure 1 below. When the generation ratio to minimum load is low in the line section where the DR is connected, typically 33% to 50% of the minimum load, then simple anti-islanding protection at the DR is sufficient with little or no changes required to the area EPS protection and coordination. The anti-islanding scheme consists of under frequency, over frequency, under voltage and over voltage. An inverse time overcurrent element is added as backup to clear c lose in faults. Distant faults are detected by the utility’s protection and the utility trips and an island is formed. The DR does not have sufficient capacity to sustain the island and the DR trips. This is option 1A.Note 1: The generation to load ratio is also expressed in terms of maximum load. In that case, the ratio is typically 15%. The rationale was that the minimum load is typically 50% of the maximum load. If that is the case, then 33% of the minimum load is equivalent to 15% of the maximum load. It is recommended that the limit be 50% of the minimum load and this be based on a measured value not an estimated value.Note 2: With modern microprocessor based protective relays, functions such as rate-of-change-of-frequency (ROCOF), vector shift, or reactive power shift are available to enhance the DR protection. This option is referred to as 1B. This is not shown on Figure 1.

This option has been utilized successfully for decades. The four new options presented below, options 2 to 5, are to be utilized when the generation ratio exceeds the limit of 50% of the minimum load.

5.2 Option 2-Overcurrent Protection and Voltage Sensing on the Area EPS, Anti-islanding Protection on the DR and Directional Overcurrent at the DR

Refer to Figure 2 below.

5.2.1 Protection Requirements at the SubstationThe utility substation is equipped with a circuit breaker (CB) and overcurrent protection. The tripping could be single pole or three pole. Directional overcurrent relaying may be applied as determined by fault study to provide co-ordination between the DR and EPS protections preventing unwanted tripping of the feeder for faults on an adjacent feeder. The addition of voltage sensing on the DR side of the area EPS interrupting device provides a check of voltage presence to block reclosing of the area EPS interrupting device should the DR fail to trip. The selection of voltage sensing is based on the agreement between the DR and the area EPS.

5.2.2 Protection Requirements at the Line ReclosuresThe line recloser is equipped with overcurrent protection. The tripping could be single pole or three pole. Directional overcurrent relaying may be applied as determined by fault study to provide co-ordination between DR and EPS, preventing the formation of unwanted islanded generation. The addition of voltage sensing on both sides of the recloser is selected to provide the voltage for polarizing the directional relaying and as a check of voltage presence before permitting reclosing. The selection of voltage sensing for reclose blocking is optional based on the agreement between the DR and the area EPS.

5.2.3 Protection Requirements at the DRReferring to Figure 2 below, the protection is designed to detect all faults on the entire feeder with the utility supply normal and the maximum level of generation. This will lead to some over tripping, for example faults on adjacent feeder or when the generation is at a minimum. These risks can only be determined by performing a fault study and placing faults at various locations on the feeder and on adjacent feeders with various levels of generation. With low levels of penetration, experience has shown this is not an issue. As more DRs are added, or a large DR is added, a point will be reached where


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effective coordination will not be possible. At that point, it becomes necessary to adopt a more sophisticated option.

The interconnection protection at the DR consists of two main components, the line protection and the anti- islanding protection. The line protection is designed to detect faults on the utility’s system and disconnect the DR. The anti-islanding protection is designed to detect an island condition when there is no fault and disconnect the DR. There is overlap in these two main categories of protection. For example, the under voltage element associated with the anti-islanding protection could respond to a line fault even though that is not its primary function. On four wire systems where single pole tripping is utilized, the tripping m a y b e delayed for single line-to-ground faults to allow time for the protection closest to the fault to operate and clear the fault. The two healthy phases will keep the DR in synchronism with the Area EPS. With today’s multi-function protection technology, both the line protection the anti-islanding protection can be implemented in one relay. Since the line protection trips the DR for all faults, it follows that the only way an island can form where the DR remains connected is due to an operating error or a problem on the transmission system supplying the distribution system.

The line protection would typically have some or all of the following protection elements:

1. 67-50. Instantaneous directional overcurrent looking into the line. Set to detect all phase-phase and three-phase faults on the entire feeder with all DRs and the utility on line.

2. 67-51. Definite time directional overcurrent looking into the bus. Set to detect all phase-phase and three-phase faults on the bus and acts as a backup to the generator protection.

3. 51N. Definite time ground (zero sequence) overcurrent. Set to detect all ground faults on the feeder. Time delay set to coordinate with the utility protection. This allows time for the utility protection to clear the fault before the DR trips. Experience has shown that more than 90% of the faults on the multi-grounded feeder are single phase line-ground faults. A very high percentage of single phase line-ground faults are transient faults and the utility recloses successfully.

4. 51. Definite time phase overcurrent. Backup protection for all phase-phase and three-phase faults.

5. 51V. Voltage controlled over timed overcurrent. Used on inverter based DR where fault current is limited by the inverter control system not the fault impedance. This will allow the overcurrent element to be set much more sensitive than it would be for a synchronous generator. When a fault occurs, the high current will be accompanied by a drop in the inverter output voltage. For example, a set point might be a current of 1.2 PU and a voltage of 0.9 PU results in a trip output.

6. 46-51. Definite time negative sequence overcurrent. Backup protection for all phase-phase faults.7. 47-59. Definite time negative sequence overvoltage. Backup protection for all phase-phase faults.8. 47-59N. Definite time zero sequence overvoltage. Backup protection for all single phase line-

ground faults and line-line-ground faults.9. 25-79. Synchrocheck. After a protection trip, the reconnection of the DR is delayed, typically 5

minutes, before the control system automatically re-synchronizes the DR with the Area EPS. This is to allow time for the Area EPS to stabilize. If the Area EPS voltage remains outside normal limits for an extended period, for example more than 15 minutes, the DR is locked out and manual operator intervention is required before the DR may be reconnected to the system. An outage of this duration is an indication of a serious problem on the Area EPS and reconnection is not permitted without consultation with the Area EPS controlling authority.

The anti-islanding protection would typically have some or all of the following protection elements:

1. 81U. Under-frequency. Two stages of timed under-frequency are normally required.Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 111

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2. 81O. Over-frequency. One stage of timed over-frequency is normally required.3. 27. Under-voltage. Two stages of under-voltage are normally required.4. 59. Over-voltage. Two stages of over-voltage are normally required.5. Rate-of-Change-of-Frequency (ROCOF).6. Vector Shift (Jump)7. Reactive Power Shift.

Note 1: By adding potential transformers (PTs) on the line side of the substation CB and the reclosers, voltage supervised reclosing may be used to prevent an out-of-phase reclose. The reclosing scheme at the substation CB or the recloser checks for line-ground voltage on all phases. If the voltage is <20% of nominal, this indicates that all DRs have successfully disconnected and reclosing is allowed to proceed. If the voltage is above 20% of nominal, reclosing is blocked. This option is referred to as 2B.

Note 2: If space is a limitation in the substation, then the PTs may be located outside the substation with a separate relay added to monitor the voltage. A communication channel is then required from this relay to the substation reclosing scheme to provide the voltage data to the substation CB reclosing scheme. For example, this channel could be fiber or a radio link since the typical distance would be <200 M.

5.3 Option 3 – Overcurrent Protection and Auto Ground or Slow Transfer Trip on the Area EPS, Directional Overcurrent on the DR, Single Line Section

Refer to Figure 3. Note that all the generation must be in the first line section. This is the same as option 2 except the following upgrades are implemented at the utility substation:

Option 3A: Add a three-phase Auto-Ground Switch at the substation. Current limiting reactors may be required.

Option 3B: consists of Option 3A, plus voltage sensing on all phases on the line side of the substation circuit breaker (CB) to provide voltage supervised reclosing.

Option 3C: consists of Option 3A, plus a slow transfer trip channel from the Area EPS to the DRs

Where the ratio of generation to load is high and relay coordination becomes difficult increasing the likelihood of a problem occurring, two steps may be taken to eliminate the risk of an out-of-phase reclose occurring or a sustained island forming. With voltage sensing at the substation, the reclosing control system can be set to check for zero voltage before permitting a reclose. If the voltage remains, this indicates that one or more of the DR protections have failed to trip the DR and the CB would remain open. Further, this means a sustainable island has formed which may result in power quality issues, primarily high or low voltage, for customers within the island. The probability of the island forming and whether that could result in a power quality problem would be part of the power system study. Assuming that the study indicates that power quality problems could exist and this is deemed an unacceptable risk, then an auto-ground switch may be used to ensure disconnection of the DR from the EPS by placing a fault on the distribution system with the substation CB open. A three phase switch will ensure the DR detects the fault regardless of the transformer connection used at the DR. It is proposed that the switch be an off the shelf standard recloser with an IED controller. To reduce the level of fault current, current limiting reactors may be used if the fault study indicates they are necessary. The switch would be placed on the line (downstream) side of the substation CB. When the line protection detects a fault, it will trip the CB and check for voltage on the line side of the CB. If voltage remains for a period of time, for example 2 seconds, indicating that all DRs have not disconnected from the Area EPS, a signal is sent to the auto ground controller to close. The auto ground controller checks that the station CB is open as indicated by a CB auxiliary switch and the line current is zero and then the auto-ground is closed. The line protection


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would initiate opening of the auto ground after a time delay, for example 5 seconds, to permit an auto reclose to proceed. If any voltage was detected after opening the auto-ground, the CB would be locked out. The close function of the CB would be interlocked with the auto-ground switch to prevent the CB from closing manually or via auto-reclose when the auto-ground switch is closed. Similarly, the manual and automatic close function of the auto-ground would be interlocked with the CB to ensure the CB was open before the auto-ground could be closed.

An alternative to the auto-ground to disconnect the DRs is a slow transfer trip channel. The permissible response time could be seconds as opposed to milliseconds for traditional high speed transfer trip. Some low cost options for the channel are radio or cellular. The protection logic would be similar to the auto-ground implementation. When a fault occurs on the line, the Area EPS line protection detects the fault trips the line and initiates a transfer trip transmission to the DRs. All DR protections must be upgraded to receive the transfer trip signal and trip the DR. The Area EPS reclosing control scheme checks for voltage on the line side of the substation CB. When the voltage goes zero, indicating that all DRs have disconnected, the CB is closed. If the voltage remains indicating that both the DR protection and transfer trip channel have failed to disconnect the DRs, the CB is locked out.

5.4 Option 4 – Distance or Directional Overcurrent Protection, Auto-Grounds or Slow Transfer Trip, Multiple Line Sections

Refer to Figure 4 below. If multiple DRs are added, it may be necessary to break the feeder into multiple line sections. This option could be implemented using directional overcurrent relays or distance relays. By using modern microprocessor based distance relays, shaped impedance characteristics permit greater selectivity to distinguish between loads, transformer inrush on reclosing, and faults on the low voltage side of the DR transformer or a load customer’s transformer. The fault and coordination study would determine which device is the most suitable. In the description below, it is assumed that distance relays are used. The advantage of this scheme over option 3 is it can accommodate a higher level of penetration on multiple line sections and could accommodate planned islanding. If islanding is not permitted, the auto ground is closed after a time delay when the substation circuit breaker or line recloser is opened. If islanding is permitted, this action is not taken. Similar to Option 3, Slow Transfer Trip is an option to the auto-ground.

Option 4A: distance or directional overcurrent with voltage supervised reclosing.

Option 4B: consists of Option 4A plus autogrounds at the substation and all reclosers.

Option 4C: consists of Option 4A plus slow transfer trip at the substation, all reclosers and at the DRs.

5.4.1 Protection Requirements for the SubstationThe circuit breaker or recloser at the substation is equipped with one set of three current transformers connected on the load side of the circuit breaker, a set of three voltage transformers connected on the station side of the circuit breaker, and a set of three voltage transformers connected on the line side of the circuit breaker. The protection at the substation will be supplied by one multifunction distance relay with the following active elements:

1. 21-Zone 1 Phase and Ground. Set to under reach the first recloser, for example 80% of the impedance of the first section of the feeder. Tripping is instantaneous.

2. 21-Zone 2 Phase and Ground. Set to over reach the first recloser but not over reach the Zone 2 of the next line section. For example set to 120% of the impedance of the first section of the feeder.


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This must coordinate with the zone 1 of the next feeder section. The time delay is set to allow time for the next line section’s protection to clear the fault. For example, assuming a 5 cycle recloser trip time (83 ms) on the next line section, the time delay might be 150 ms.

3. 21-Zone 3 Phase and Ground Backup Protection. Set cover the entire feeder with a time delay sufficient to allow time for all downstream protections to operate first, for example a delay of 500 ms.

4. 32-1. Reverse Power Flow. This protection is required when the total size of the generation is sufficient to exceed the limits of the substation transformer. This element would have a time delay of several seconds to avoid tripping for faults on the transmission system or temporary reverse flow during switching.

5. 32-2. Reverse Power Flow. To protect for faults on the transmission system supplying the substation. A reverse directed impedance element may also be used for this purpose. For either approach, the protection requires a time delay to coordinate with the transmission system protection. For example, this delay may be in the order of 100 ms.

6. 27-79. Reclosing. The reclosing would be under-voltage plus time. The reclosing scheme would check for normal voltage on the station side of the circuit breaker and a zero voltage on the line side indicating that the transmission system is normal and all DRs successfully detected the fault and are isolated before reclosing.

7. 25-79. Reclosing. If planned islanding is deployed, synchrocheck reclosing could be added to allow reconnection of the island to the Area EPS without interruption.

8. Three Phase Auto-Ground Switch. If islanding is not permitted, the substation CB is tripped, the protection checks for voltage. If voltage remains after a time delay, for example 2 seconds, indicating all DRs have not disconnected, the auto ground is closed for a period of 1 second and then reopened. The reclosing scheme checks voltage. If it is zero, the CB is closed. If not, the CB is locked out.

OrSlow Transfer Trip transmit and receive. If islanding is not permitted, the substation line protection trips the CB for a line fault and initiates a transfer trip transmission. The Areas EPS reclosing scheme checks for voltage on the line side of the CB. If the voltage is zero, the CB is closed. If it remains after a time delay, for example 3 seconds, indicating all DRs have not disconnected, the CB is locked out.

5.4.2 Protection Requirements for the Line ReclosersEach line recloser is equipped with one set of three current transformers connected on the station side of the recloser, a set of three voltage transformers connected on the station side of the recloser, and a set of three voltage transformers connected on the line side of the recloser. The protection at the recloser will be supplied by one multifunction distance relay with the following active elements:

1. 21-Zone 1 Phase and Ground. Set to under reach the next line section, for example set to 80% of the apparent impedance of the downstream line section of the feeder. Tripping is instantaneous.

2. 21-Zone 2 Phase and Ground. Set to over reach into the next line section, for example set to 120% of the apparent impedance of the line section. It must not over reach the Zone 2 of the next line section. The time delay is set to allow time for the next line section’s protection to clear the fault. For example, if the recloser trip time was 100 ms on the next line section, the recommended time might be 200 ms.

3. 21-Zone 1 Phase and Ground Reversed. Same as forward directed elements.4. 21-Zone 2 Phase and Ground Reversed. Same as forward directed elements.5. 27-79. Reclosing. Same as substation. Check for voltage on the station side and zero voltage

on the line side.6. 25-79. Reclosing. May be used with planned islanding, same as substation.


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9. Three Phase Auto-Ground Switch. Same as substation or Slow Transfer Trip transmit and receive. Same as substation.

5.4.3 Protection Requirements at the DRThe settings for each DR impedance relay on the feeder will be based on the maximum generation being on line. This may result in over tripping when the generation is not at a maximum. The line protection would typically have some or all of the following protection elements:

1. 21-Zone 1 Phase and Ground. Set to under reach the line section where the DR is installed, for example set to 80% of the apparent impedance of the line section. Tripping will be instantaneous.

2. 21-Zone 2 Phase and Ground. Set to over reach the line section where the DR is installed, for example set to 120 % of the apparent impedance of the line section. Time delay set to allow time for the protection closest to the fault to operate, for example 200 ms.

3. 21-Zone 3 Phase and Ground Reverse. Set to detect faults on the low voltage side of the DR’s electrical system.

4. 51. Definite time phase overcurrent. Same as option 25. 51 V. Voltage controlled overcurrent. Same as option 2.6. 46-51. Definite time negative sequence overcurrent. Same as option 27. 47-59. Definite time negative sequence overvoltage. Same as option 28. 47-59N. Definite time zero sequence overvoltage. Same as option 29. 25-79. Synchrocheck. Same as option 2.10. Slow Transfer Trip Receive

Anti-islanding protection:Same as option 2.

5.5 Option 5 – Impedance or Directional Overcurrent Protection and Teleprotection Refer to Figure 5. This option is similar to option 4 with high speed communications added for protection purposes. Communications used for protective relaying is often referred to as teleprotection . The substation, each recloser and the DR will be equipped with pilot scheme logic such as directional comparison blocking (DCB) transmit and receive and transfer trip (TT) transmit and receive. The protection elements will be identical to option 4 except directional comparison blocking will allow the DRs to remain on line when the fault is not on their line section and they are not in an island condition. To achieve this, the Zone 1 elements of the DR will be set to under reach the apparent impedance of the line section where they reside and will be instantaneous. The Zone 2 elements of the DR will be set to overreach the apparent impedance of the line section where the DR is connected and tripping will be delayed sufficient time to allow for a DCB signal to arrive. The advantage over option 4 is high speed tripping of all terminals for in zone faults and less risk of over tripping for out of zone faults.

5.5.1 Protection Requirements for the SubstationThe protection elements will be the same as option 4 plus the following:

1. 21-Zone 4 Phase and Ground Reversed. This element will be used to initiate a directional comparison block signal and will provide a backup protection to trip the recloser after a time delay sufficient to allow clearing of a fault by the slowest protection on the feeder, for example 500 ms,

2. Directional Comparison Blocking (DCB) Transmit and Receive.Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 115

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3. 21 Zone 2 Phase and Ground. This element will have a time delay to allow sufficient time for the DCB signal to arrive. If no block signal arrives, the CB is tripped. If a block signal is received and the fault has not cleared after the time delay, for example a delay of 500 ms, the CB is tripped.

4. Transfer Trip Transmit and Receive. Operation of the Zone 1 protection or the opening of the CB will initiate a Transfer Trip Transmit (TTTX). A Transfer Trip Receive (TTRX) will trip the CB and initiate a reclose.

5. 27-79. Same as option 4 except reclosing would be initiated by a Zone 1 or Zone 2 when no DCB has been received indicating an in zone fault. A Zone 2 timed trip will not initiate a reclose.

5.5.2 Protection Requirements for the Line ReclosersEach line recloser is equipped with one set of three current transformers connected on the station side of the recloser, a set of three voltage transformers connected on the station side of the recloser, and a set of three voltage transformers connected on the line side of the recloser. The protection at the recloser will supplied by one multifunction distance relay with the following active elements:

1. 21-Zone 1 Phase and Ground. Set to under reach the next line section, for example set to 80% of the apparent impedance of the downstream line section of the feeder. Tripping is instantaneous.

2. Directional Comparison Blocking (DCB) Transmit (TX) and Receive (RX). The reverse directed Zone 2 elements initiate DCB TX for the forward directed protection and the forward directed elements initiate DCB TX for the reverse directed protection. The Zone 2 forward and reverse elements will trip after a short delay if no DCB signal is received.

3. 21-Zone 2 Phase and Ground. Set to over reach the line section, for example set to 120% of the apparent impedance of the downstream line section. This element will have a time delay to allow sufficient time for the DCB signal to arrive. If no block signal arrives, the recloser is tripped. This is referred to as a Zone 2 Fast Trip. Operation of this element will also initiate a DCB signal for the reverse line protection.

4. 21-Zone 1 Phase and Ground Reversed. Set the same as forward directed elements.5. 21-Zone 2 Phase and Ground Reversed. Set the same as forward directed elements. Operation

of this element will also initiate a DCB signal for the forward line protection.6. 27-79. Reclosing. Same as substation.7. Transfer Trip Transmit and Receive Forward and Reversed. When a Zone 1 protection or a Zone

2 Fast Trip operates at the recloser, a TTTX signal will be initiated. When a TTRX is received, the recloser is tripped. If islanding is not permitted, the signal is cascaded on. Referring to Figure 4, if the fault was in Line Section 1 and the substation protection Zone 1 operated and sent a TTTX, the arrival of the TTRX signal at RC1 would result in a TTTX to DR2 and RC2. If islanding is permitted, then the TTRX trips RC1 but does not initiate a TTTX.

5.5.3 Protection Requirements at the DRThe line protection would typically have the following protection elements:

1. 21-Zone 1 Phase and Ground. Same as option 4 except this element will also initiate a TTTX. 2. 21-Zone 2 Phase and Ground. Same as option 4 except a Zone 2 Fast Trip will occur if no DCB signal is received.3. 21-Zone 3 Phase and Ground Reverse. Same as option 4 except this element will also initiate a DCB transmit signal. 4 51. Definite time phase overcurrent. Same as option 2.5 51 V. Voltage controlled overcurrent. Same as option 2.6. 46-51. Definite time negative sequence overcurrent. Same as option 2.


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7 47-59. Definite time negative sequence overvoltage. Same as option 2.8. 47-59N. Definite time zero sequence overvoltage. Same as option 2.9 25-79. Synchrocheck. Same as option 1 and 2.

Anti-islanding protection:Same as option 2.

6.0 Special Protection Requirements and Options for Inverter Based DR Inverter based generation differs from rotating machines in that the inverter contribution to fault current is low to none. The preceding discussion assumed the DR consisted of a synchronous machine. Much of the DR now being connected, especially photovoltaic, utilizes inverters. The behavior of inverters is very different than that of synchronous machine, especially during faults. Inverters are inherently protected in current to avoid damage to their semiconductor output bridge. During a fault, the small current contribution to the fault will result in a quick voltage collapse that will be detected by the inverter, triggering its disconnection within a few cycles according to IEEE 1547 4.2.3. This built in protection takes the place of traditional overcurrent protection.

Inverters are commonly used to connect small PV systems on single phase systems. They often connect to the power panel of single premises in parallel with other load and other premises. These units are usually ranging from 1 to 10 kW units. They do not measure voltages or currents on the high side of their distribution transformers and since they usually are in parallel with other customers, they do not have a complete picture of the transformer load either. It is currently the practice to rely on their voltage protection features to disconnect the inverters from the EPS when there is a low impedance fault and to rely on their anti-islanding features to disconnect from the EPS in case of islanding due to fault detection from the EPS and de-energization of the fault by the EPS. Considering the low cost and small size of these inverters, this may be the only practical approach.

Consequently, for Class 1 [1547.3 5.3] systems (<250kW), internal protection is considered sufficient as long as the utility in charge manages the number of DR connections on a given feeder so that:

1. The load data and inverter generation forecast have little likelihood to be matched within 10%. 2. During these matched real power events, the expected reactive load is more than 10% different from

the total VAR sources on the feeder.

[ref: ROPP, M.E., J.G. Cleary and Babak Enayati. “High Penetration and Anti-Islanding Analysis of Multi-Single Phase Inverters in an Apartment Complex, 2010 IEEE Conference on Innovative Technologies for an Efficient and Reliable Electricity Supply (CITRES), 27-29 Sept. 2010, pages 108]

The internal protection schemes of certified inverters detailed above can also be used with success to detect possible fault or faulted island conditions for Class 2 [1547.3 5.3] plants of 250 KW to 1.5 MW as long as the instantaneous generation to load power ratio is guaranteed not to be greater than 90%. In the event that the local generation to total load ratio is above 90%, or for Class 3 [1547.3 5.3] plants (1.5 to 10MW) then the schemes presented in Section 5.0 should be applied.


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Figure A. Response to Island Conditions

Another solution is to use a high speed communication scheme as described below using synchrophasors. One issue with the implementation of local fault and faulted island schemes is that the sensitivity of the 81 O/U, 27, 59, and even ROCOF can result in the disconnection of generation from the distribution system for remote faults. To enable an inverter to distinguish between a utility outage and a transient disturbance the wide area information provided by synchrophasors can be used to keep the generation online during these remote transient conditions. Wide-area information is available to each inverter and this system requires no unnatural forcing of the connected frequency, power, or voltages. The IEDs acquire voltage phasor measurements from their corresponding sites. The IEDs send synchrophasor messages to the Synchrophasor Vector Processor (SVP) and the SVP calculates the difference between the local and remote synchrophasor angles. The change in the difference angle over time defines a slip frequency. The change in slip frequency with respect to time defines the acceleration. When a DR separates from the EPS there will be both slip and acceleration.

[citation: Solar Generation Control With Time-Sychronized Phasors, Michael Mill-Price, Mesa Scharf, and Steve Hummel, PV Powered, Michael Ropp and Dij Joshi, Northern Plains Power Technologies, Greg Zweigle, Krishnanjan Gubba Ravikummar, and Bill Flerchinger, SEL]


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Figure B. Island Detection CharacteristicsWhile not within the scope of this writing group’s effort, it is also noted that the behavior of inverters on loss of load has also yielded surprising results. Especially in the case of inverters which export power into the substation, the opening of a substation breaker can result in up to a total loss of load. Some inverters have been observed by one utility, Southern California Edison, to produce transient over- voltages of up to 220% for several cycles in this event. These over-voltages can be damaging to other connected customers and equipment.

7.0 Special Protection Requirements and Options for Wind Turbine Based DR

Typical sizes for wind turbines today are 1 to 2.5 MW. Wind turbines are often located in large wind farms where the total capacity is 100 MW or more. In that case they are connected to the transmission system. Due to government incentives, there is now a trend to locating a small number in one location. For example, in Ontario, 10 MW farms are common. There are four basic types of wind turbines as follows:

Type 1. Conventional Induction GeneratorType 2. Wound Rotor Induction Generator with Variable Rotor ResistanceType 3. Doubly–Fed Induction GeneratorType 4. Full Converter Interface

The biggest issue from an interconnection protection perspective is how to represent the turbine for the purposes of a fault study. The study requires an accurate equivalent circuit that can be inserted into an existing fault study program. Types 1 and 2 turbines act essentially like an induction generator. Therefore, they do not present a problem. Type 3 and type 4 devices react very differently to faults than a synchronous machine or induction generator due the response of their control systems. Type 3 systems can have a discontinuous response. The response is due to controls rather than physics, provided the fault is not so severe as to result in crowbar operation. If it is not crowbarred, it behaves much like a Type 4. If crowbarred, it looks like an induction generator for as long as the crowbar is on, but in many schemes, the crowbar is transient, longer for more severe faults, shorter for less severe faults. For type 4 devices, details of their behavior are defined by proprietary controls and not fundamental physics. Manufacturers are reluctant to publish data on the type 4 systems as a competitor could use the data to reverse


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engineer the product. Type 4 WTGs behave in a similar manner to inverters. The DC bus is supplied from a different type of source. Various existing distribution power system modeling software packages used by utilities are capable of modeling inverters or Type 4 WTGs. Some WTG suppliers are willing to provide the necessary data to complete the model for a distribution system application as these parameters are required for interconnection to the Bulk Power System (Transmission Level) which is where most WTGs are being connected today. The issue of the supply of adequate data by the manufacturer must be resolved by the industry in order to apply this technology. Discussions are now underway in North America and Europe to address the problem. It is our opinion at the moment that distance relays and transfer trip can be applied effectively. The cost of transfer trip may be a barrier to deployment for smaller wind farm installations.


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Figure 1: Option 1. Overcurrent Protection on the Area EPS, Anti-islanding Protection at the DR


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Option 2Generation Connects to EPS with addition of directional elements by EPS owner as determined by power system study.

Overcurrent and Directional OC Protection on the Area EPS, Directional OC at DR

Recloser with IED ANSI Device Names

Recloser RE/CL (RC1, RC2) 51 Recloser CurvesSingle Pole or Three Pole 67, 67-51, 67N, 67N-51

Line section 1 Line section 2

Load

CBRE

CL

RE

CL

v

DR1

Load

v

DR1

DRLoad

v

DR1

DR

Line section 3Utility

Substation

CB

CB

CBDR

RC1 RC2

Utility Substation ANSI Device Names: CB

CB Relaying (Electromechanical) Single Pole or Three Pole 50, 51, 27, 79

CB Relaying Intelligent Electronic Device 67, 67-51, 67N, 67N-51 DR (Distributed Resource) ANSI Device Names

DR (Intelligent Electronic Device) Three Pole Tripping

Line Protection 67, 67-51, 67N/51N, 51, 51V, 46-51, 47-59, 47-59N, 25-79

Anti-Islanding 81O/81U, 27/59, dF/dt, Vector Shift (Jump), 32var

Figure 2: Option 2. Overcurrent Protection at the Area EPS, Directional Overcurrent at the DR


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v

DR1

Line section 1

Load Load Load

v

DR1

v

DR1

DR

CBUtilitySubstation

AG

RE

CL

Option 3Generation Connects to EPS with addition of Auto Ground by EPS owner as determined by power system study.

Overcurrent and Directional OC Protection on the Area EPS, Directional OC at DR

CB

DR DR

Utility Substation ANSI Device Names: CB

CB Relaying (Electromechanical) Single Pole or Three Pole 50, 51, 27, 79

CB Relaying Intelligent Electronic Device 67, 67-51, 67N, 67N-51

CB

CB


Recloser RE/CL (RC1, RC2) 51 Recloser CurvesSingle Pole or Three Pole 67, 67-51, 67N, 67N-51

DR (Distributed Resource) ANSI Device Names




Figure 3: Option 3. Overcurrent Protection and Auto Ground or Slow Transfer Trip on the Area EPS, Directional Overcurrent on the DR, Single Line Section


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RC1


RC1

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CBRE

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RE

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v

DR1

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v

DR1


Substation

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Option 4.Generation Connects to EPS with addition of Auto Ground by EPS owner as determined by power system study.

Directional OC Protection and/or Impedance Relaying on the Area EPS, Directional OC and/or Impedance Relaying at DR

Utility Substation ANSI Device Names

CB Relaying IED 21-Z1, 21-Z2, 21-Z3, 32-1, 32-2, 27-79Intelligent Electronic Device IED 27-25, 67, 67-51, 67N, 67N-51


Recloser RE/CL (RC1, RC2) 21-Z1, 21-Z2, 21-Z3, 32-1, 32-2, 27-79Single Pole or Three Pole 27-25, 67, 67-51, 67N, 67N-51

IED

DR DR DR

CB

CB





Figure 4: Option 4. Distance Protection, Auto Grounds or Slow Transfer Trip, Multiple Line Sections


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RC1


RC1

Load

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RE

CL

RC2

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v

DR1

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DR1


Substation

Option 5Generation Connects to EPS with addition of protection grade communications channel and pilot scheme logic is employed.

Directional OC Protection and/or Impedance Relaying on the Area EPS, Directional OC and/or Impedance Relaying at DR

Utility Substation ANSI Device Names

CB Relaying IED 21-Z1, 21-Z2, 21-Z3, 32-1, 32-2, 27-79Intelligent Electronic Device IED 27-25, 67, 67-51, 67N, 67N-51


Recloser RE/CL (RC1, RC2) 21-Z1, 21-Z2, 21-Z3, 32-1, 32-2, 27-79Single Pole or Three Pole 27-25, 67, 67-51, 67N, 67N-51


Line ProtectionDR (Intelligent Electronic Device)

21-Z1, 21-Z2, 21-Z3, 67, 67-51, 67N, 67N-51, 51,51V, 46-51, 47-59, 47-59N, 25-79


IED

DR DR DR

CB

CB

Pilot Scheme Pilot Scheme Pilot Scheme

Pilot SchemePilot Scheme

Pilo

t Sch

eme

Pilo

t Sch

eme

Pilo

t Sch

eme

Figure 5: Option 5. Distance Protection, Teleprotection, Multiple Line Sections


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Annex G (Informative) -- North American Distribution System Design and Operating Practices

1.0 Four Wire SystemsThe substation transformer for four wire systems is a wye configuration normally solidly grounded or grounded through a low impedance to limit fault current. For four wire systems typical voltages range up to 34.5 kV. The line is grounded with ground rods along the line. The primary and secondary neutrals are connected together at the supply transformer at the load customer sites. Typically, the majority of the customers are single phase. The transformer connection at the customer site is typically grounded to minimize TOV. Three pole tripping is normally used at the Area EPS substation. Three pole tripping may be used along the line if there is a predominance of three phase customers but single pole tripping is more often used. Since most faults are single line-to-ground faults, interrupting only that phase improves reliability. Reclosers are more commonly used on the three phase main trunk. Both reclosers and fuses are used on single phase laterals or spurs off the main trunk. Fuses are the most common mode of protection for the customers with three phase transformers.

Protection at the Area EPS substation may consist of a low set instantaneous, a high set instantaneous and an inverse time overcurrent protection. Many utilities use a “fuse saving” strategy where the low set instantaneous protection operates first to clear the fault. Since most faults are transient, the fault is cleared before the fuse is damaged. This includes the fuse on the on a lateral. This protection is set to detect faults on the entire feeder. The high set instantaneous only operates for faults close to the substation and is designed to prevent damage to the substation equipment. The inverse time at the substation must coordinate with the first recloser or fuse and is also set to see the entire feeder. The circuit breaker or recloser at the substation is multi-shot. Reclosers along the line typically utilize inverse time overcurrent characteristics. They are also multi-shot with two fast operations followed by two slow operations being the most common selection. The two fast operations are designed to protect downstream fuses for transient faults. The two slow operations are designed to blow a downstream fuse for permanent faults on single phase laterals.

The second common protection approach used on distribution systems is referred to as a trip saving strategy. It differs from the fuse saving strategy in that the low set instantaneous protection is set to not operate for faults on a single phase lateral.

Temporary overvoltage is significant problem for four wire systems when connecting DR. The equipment is typically rated for 1.25 PU of the phase-neutral voltage. Mitigation of TOV is accomplished through effective grounding, solid grounding or the addition of grounding banks. citation for TOV for IEEE C62.41.2 and C37.90.1. It is often a balancing act between controlling TOV and controlling the amount of ground current being injected into the Area EPS. Increasing the neutral ground impedance increases TOV but reduces ground current.

2.0 Three Wire Systems. Three wire systems are uniground systems where the substation transformer is a wye configuration grounded typically through an impedance to limit the fault current. Typical voltages are 34.5 kV, 44 kV and 69 kV. These are also referred to as sub-transmission systems. The higher operating voltage allows for larger loads and DRs to be connected. These systems are grounded at the supply station only and all customers are connected phase-phase and not phase to neutral. The neutral conductor is not extended beyond the substation. Single phase customers are rarely supplied off these systems and all circuit breakers and reclosers are three phase.


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The transformer connection at the customer site is typically ungrounded to eliminate a source of ground current which could desensitize the Area EPS protection. Single pole tripping is not used to prevent single phasing three phase customers. In line fuses are not used for the same reason. Fuses are the most common mode of protection for the customer’s three phase transformer.

Protection at the Area EPS substation normally consists of a low set instantaneous, a high set instantaneous and an inverse time overcurrent protection. The reclosing scheme at the substation is usually multi-shot. Reclosers along the line typically utilize inverse time overcurrent protection and are also multi-shot.

Temporary overvoltage is not normally a problem on three wire systems when connecting DR since the equipment is rated for full phase-phase voltage.

The interconnection protection system must recognize the difference between the uniground and multi-ground system but it is not anticipated that the uniground system will present any significant protection issues that would not have been addressed for multi-ground system.

3.0 The Three Phase Ungrounded SystemIt is our understanding that there are very few of these systems in use in North America. Furthermore, they are being phased out. Therefore, we propose to ignore these systems in our future analysis

1.0 The Concept of Protection ZonesAs indicated above, utilities in North America employ a variety of different philosophies for the design and operation of their distribution systems. When it comes to providing protection, although the philosophies may be different, they all utilize protection zones to determine the response of the protecting device. This applies to schemes based entirely on fuses, those based entirely on reclosers, and those based entirely on circuit breakers and protective relays. In distribution systems, the protection system is typically a hybrid of fuses, reclosers, circuit breakers and protective relays. Modern reclosers have built in IEDs that act as the controller for the recloser. In essence, they are equivalent to the circuit breaker and a separate protective relay in one package.

Refer to Figure 1 below. The protection zones are indicated as Zone 1, Zone 2 and Zone 3. This is from the perspective of the utility substation looking out on the distribution system towards the DR. As indicated above, the zones do not depend on the protecting device. For the purpose of this discussion it is assumed that the protection at the utility substation utilizes circuit breakers (CBs) and separate protection IEDs, the reclosers are modern reclosers with IEDs as controllers, and the DR utilizes a circuit breaker and a separate protection IED. Further, this is a four wire system with single pole tripping and the transformer connection at the DR is Yg:Yg. The Zone 1 is typically set to under reach the first lateral off the main three phase trunk. The lateral could be a three phase, two phase, or single phase line section. The Zone 1 protection element is set to trip instantaneously. Faults within this zone must be cleared quickly to minimize equipment damage and ensure that the feeder fault is cleared before the substation bus protection operates which would unnecessarily disrupt service to the customers on the un-faulted F2 feeder. The Zone 2 element is set to overreach the two reclosers RECL1 and RECL2. The most common protection element in use on distribution systems is the inverse time overcurrent element which results in a reduction in trip time as the fault current increases. Figure 2 below has examples of these curves. Reclosers RECL1 and RECL2 also have Zone 1 elements that would be set to operate for faults in the forward direction. For close-in faults, these elements will operate before the substation Zone 2 element. Similarly, the RECL3 Zone 1 element would operate before the RECL2 Zone 1 element for faults in Line section 3. The Zone 3 substation protection is set to cover the entire feeder. It is a backup protection that will only operate if another protection fails. For example, assume that RECL1 failed to operate, then the substation Zone 3 element would clear the fault. Note that this protection dose not reach through the DR transformer


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Refer to Figure 3 below. The protection at the DR consists of the DR protection and interconnection protection. The DR protection is designed to protect the DR generating device. For example, if the DR is a synchronous machine, the protection could consist of generator differential, generator unbalance, loss of field etc. plus a backup overcurrent element set to operate for faults on the distribution system. The primary function of this protection is to protect the generating device. Its secondary function is to protect the distribution system. This protection most often comes as a package with the generating device. The interconnection protection has the primary function of protecting the distribution system and a secondary function of acting as a backup to the generating device. Note that both Zones of the interconnection protection overlap with the DR protection Zone.

The interconnection protection consists of two main categories, line protection and anti-islanding protection. The line protection is designed to detect faults on the distribution system. The anti-islanding protection is designed to detect an island condition when there is no fault. In this example, the interconnection Zone 1 protection is set to reach and trip instantaneously for faults just beyond RECL2 and RECL3. The interconnection Zone 2 protection is set to cover the entire feeder with a sufficient time delay to permit protections close to the fault to operate and clear the fault. If the DR short circuit capacity is relatively small in comparison to the short circuit capacity of the utility substation, which is often the case, then for a fault in Line section 1, the F1 CB would open, RECL2 would not because the fault current supplied by the DR is insufficient to trip RECL2. The DR would feed the fault until the DR protection operates to trip CBDR1. If the fault was beyond RECL1 at Y, then the DR is not required to trip. To prevent this from happening, a time delay is added to the DR protection to provide coordination between the RECL1 protection and the DR protection. If the DR is large, then for a fault in the same location, the DR could trip RECL2 forming an island. When CB1 and RECL2 reclose, an out-of-phase reclose event could occur. To prevent this event from occurring, the DR protection must either initiate tripping of CBDR1 before RECL2 opens to clear the in-feed from the DR or directional relaying must be installed on RECL2 to prevent it from tripping. Where single pole tripping is used, for single-line-to ground faults only the faulted phase will open. The two un-faulted phases will normally keep the DR in sync with the utility. Therefore, there is very little risk of an out-of-phase reclose occurring. This will allow longer coordination time delays to be added for single-line-to-ground faults than for line-line or three-phase faults.

The reach of the DR interconnection Zone 2 protection does not need to be set to detect downstream faults at X or Z. However, depending on the location of the DR on the feeder, if it is set to reach the utility substation bus, then it will also reach X and Z, This results in some unnecessary over tripping which is undesirable but a failure to trip is unacceptable. To prevent the over tripping, pilot schemes may be used to send a signal to the remote terminal indicating that the fault is not on the protected line and therefore the remote terminal is not required to trip. These schemes are quite costly and therefore not commonly used on distribution systems.


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Figure 1. Protection Zones from the Utility Substation Towards the DR


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Figure 2. Examples of Inverse Time Overcurrent Characteristics


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-Figure 3. Protection Zones from DR Towards the Utility Substation

5.0 Reclosing TimeIEEE 1547 sections 4.2.1 and 4.2.2 requires Distributed Resources (DR) interconnecting with an Electrical Power System (EPS) to disconnect from a faulted EPS and to do so prior to the utility’s re-energization of the EPS. IEEE 1547 requires anti-islanding features of DR to operate within 2 seconds. The anti-islanding techniques using UF, OF, UV and OV require time to detect an island condition; if the utility’s disconnect device recloses faster than 2 seconds, then the DR may still be connected and an out of synchronism parallel may occur. Therefore one recommendation is to set the utility’s re-energization of the EPS to a 2 seconds or longer. This recommendation is for both station breakers and for line reclosers.

Additional Considerations Voltage Supervised RecloseAnother consideration is adding a voltage measurement on the DR side of the disconnect device to supervise reclosing. This would prevent the EPS from reclosing into an energized island. The need for this supervision is based on likelihood of the load to generation ratio being balanced after the disconnect device operates (See section 5 for anti-islanding discussion.) Also, the disconnect device reclosing could be supervised by a synchronous checking relay. This option is available for the EPS protection package at the station and is also commercially available from some recloser manufacturers as part of their protection package.Fast Reclose and Transfer Trip


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Some utilities have a standard practice for a quick reclose to limit the outage time for their customer’s load. If the EPS chooses to use a reclosing time of less than 2 seconds, options available are to install either a transfer trip from the EPS to the DR. When a fault is detected at the EPS, the transfer trip signal will lockout the DR and allow the EPS disconnect device to reclose. Supervision from either a voltage check or synchronous relay could be used to prevent reclosing before the DR is off line. Another option is to install a ground switching device. These options have the potential to operate the DR disconnect device in substantially less than 2 seconds and then allow the EPS to reclose their station breaker or line recloser. The exact time will depend on the system, including communication time and device operation time. Feeder Configuration Switching Changes

The installation of any transfer trip method should consider alternate system configuration such as during feeder breaker maintenance and outage restoration. Under these scenarios, the generation and remainder of the feeder could be connected through a tie switch to another source. Some utility practices include disconnecting DG’s on a feeder that is in any alternative system configuration state. The other option is to install a transfer trip mechanism (either direct transfer trip or grounding switch) and voltage measurement from all potential EPS source breakers or reclosers.

Single Pole TrippingSome EPS practices include single pole tripping for single phase faults on their distribution system.

Auto-Ground for Back-Up Anti-Islanding Protection of DRThe premise of using an auto-ground in Option 3 is that grounding the system, following opening of the associated protection device, will cause DRs that are connected and do not react initially to the islanding event, will respond to the application of the bolted fault detected by their line protection. As such, the auto-ground is a back-up to local anti-islanding and line protection of the generators. While this concept may initially come across as unconventional and possibly unwise, on further inspection it is shown to be simple, scalable and effective. In short, it is an elegant solution that doesn’t require communication or changes on the part of the DR proponent.

Advantages of the approach include the following: The approach forces the DR to revert to their line protection and in doing so guarantees the DR

will be tripped offline. Can be constructed using standard distribution equipment. No communication between the Area EPS and the DR is required. Scalable – works for any penetration level of DR, can be added to only the required protection

device. Will limit, and in some cases eliminate, transient overvoltage problems. No impact on low voltage ride through requirements for distribution connected wind farms.

That being said, there are some disadvantages of the concept. These include: Each generator will be subjected to a short circuit for every operation of the protection device

(this can be mitigated by adjusting the time delay between the opening of the protection device and application of the auto-ground).


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There is a possibility, albeit limited, of tripping down-line protection devices (e.g. In-line recloser RC in Figure 1 for operation of AG1) that are located between the auto-ground and the DR installation as a result of back feed by the DR.

Little operating experience and no availability of off-the-shelf packaged products.

v

DR1

Line section 1

Load Load Load

v

DR1

DR

CBUtilitySubstation

AG1

RE

CL

CB

DR

CB

CB

RC

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RC

Figure 1. Auto-Grounds Paired with Substation Breakers and In-Line Reclosers

Closer inspection reveals that there are a number of issues that need to be taken into consideration in the design of the system. These include, but may not be limited to the following:

Whether or not a grounding impedance should be associated with the auto-ground. The setting of the time delay between opening of the protection device and the application of the

auto-ground. Identify cases where the approach cannot be used, for instance:

o On very long feeders that limit the ability to see the ground from the DR (in these cases, the significant reactive load associated with the line generally ensures that DR will disconnect and auto-ground would not be required anyway.)

o Cases where islanding is permitted. If the system is used on systems with single pole tripping, the logic must be revised to apply the

auto-ground to the open faulted phase. This may result in other issues such as unacceptable levels of TOV. See Appendix 1 of Annex G.

The impact of the approach on a utility’s protection planning philosophy should be evaluated prior to application.

TOV Prevention

6.1 Detecting feeder ground faults at the DG facility locally and tripping the DG quicklyOne way to limit the consequences of overvoltage during SLG faults is to limit its duration. This can be done by detecting the overvoltage and shutting down the generator as quickly as possible prior to islanding. For ungrounded interfaced DG, typical scheme consists of detecting zero sequence voltages (3V0) by connecting grounded-wye to delta PT bank and an overvoltage relay (59G) connected at the broken delta.


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The major issue with this approach is that if it is used in lieu of effective grounding, then the overvoltage still occurs, and the DG may not be tripped before damage occurs to utility equipment and/or customer loads. This approach works best if the 59G relay and breaker clearing time are fast enough to trip the generator off-line before the upstream utility protection opens. However, practically this cannot always be achieved due to the need of time delay in the DG tripping to avoid nuisance trips. This will not serve the intended purpose if either the loads could be damaged in just a few cycles of extreme overvoltage or if the surge arrestors are not rated for such voltages.

6.2 Use a transfer trip signal to trip the DG prior to islandingA transfer trip (TT) signal from the feeder circuit breaker at the Transformer Station (TS) or from the upstream in-line re-closer to the DG can limit the duration and help in preventing probable damages due to the overvoltage much in the same way the 59G relay can. Obviously, TT application is the most deterministic method for preventing DG island as all other anti-islanding schemes have some sort of “non detection zones”. TT can also be employed with greater speed and without issues of nuisance trips and should be more reliable than the broken delta protection method. However, besides the cost implications, the drawback is that the generator still can create an overvoltage until it is tripped as shown in sub-section 5.3.2 and there may be other scenarios where the feeder breaker does not trip and no TT signal sent (open load side jumper or conductor), but yet there is a fault on the line and an open feeder section between the DG and TS. In such cases the TOV is not expected to be high as in case of DG island but could be of similar magnitude as prior to jumper opening.

6.3 Use “effective grounding” of the DG interfaceEffective Grounding on the power system is grounding through a sufficiently low impedance such that for all system conditions the ratio of zero-sequence reactance to positive-sequence reactance X0/X1 is positive and not greater than 3, and the ratio of zero-sequence resistance to positive-sequence reactance R0/X1 is positive and not greater than 1.“Prevention of TOV at the grass root, i.e. at the source, is always better than reacting after its occurrence”. The effective grounding of the DG interface is the safest way to ensure that the TOV is prevented at the source itself.6.3.1 For existing DG installations with ungrounded HV windings on the interface transformer or

for DG connecting inside a load facility supplied by the utility’s existing Delta/star-gnd distribution transformer.

Grounding Transformers located at the Point of Common Coupling (PCC) will likely be the most practical means of providing a suitable ground source. It is obvious that additional ground sources at the PCC will increase ground fault levels and can reduce utility’s in-feeds to SLG faults. That will require modifications to the utility’s ground fault protections to increase their sensitivity. Practically, unbalanced load conditions limit the achievable sensitivity of the utility’s ground fault protections. The addition of ground sources along the feeder should be kept to a minimum, sized only to as required to prevent TOV from becoming excessive.Connection of a 1000 kVA grounding transformers with 2.65% impedance at the PCC of a 19.8 MVA DG will be effective in reducing TOV for ungrounded DG to acceptable


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levels. The reduction in TOV is shown in Figures 11 & 12. Figure 11 shows the feeder-end TOV reduced to 130% and Figure 12 shows the TOV at the PCC reduced to 122%.


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Figure 15 (TOV for feeder-end SLG Faults (Utility + DG + Grounding Transformers)

- 1000 kVA grounding transformer is used to reduce TOV- The grounding transformers are 2.65% impedance, solidly grounded- TOV is reduced from 148% (Figure 5) to 129%


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Figure 16 (TOV for SLG Faults at PCC (Utility + DG + Grounding Transformers)

- 2 X 500 kVA grounding transformers are used to reduce TOV- The grounding transformers are 2.65% impedance, solidly grounded- TOV is reduced from 158% for a fault at the PCC (Figure 6) to 129%

6.3.2 For new DG connections (Green-field applications).It is easier to achieve effective grounding in green-field DG facilities. This can be accomplished by properly selecting the DG interface transformer with appropriately sized “neutral grounding reactor” (NGR). The DG interface transformer’s winding configuration primarily governs the zero sequence impedance of the DG facility. Star-gnd (HV-utility side) and delta (LV-generator side) winding configuration is the most suitable DG interface transformer winding connection. The lowest TOV level can be achieved by solidly grounding the neutral of the Star winding, but this can jeopardize the utility’s ground protection if there are number of such DG facilities on the same feeder. In order to maximize DG connections the ground fault contribution from DG facilities needs to be restricted to an extent such that the utility’s ground fault protection is not over desensitized and the TOV is controlled to acceptable levels. By inserting an appropriately sized NGR in Star neutral to ground path, the desired effect can be achieved. For the same impedance, the reduction in TOV will be similar to the grounding transformers case as shown in Figure 12.

The NGR, Xn, or grounding transformer, can be sized based on a Thevenin Equivalent of the Positive (X1DG) and Zero Sequence (X0DG) Reactance of the DG Facility (example:


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at the Point of Connection with the Point of Connection OPEN) that will result: (reference 8.5) For Conventional (Rotating) Generators:

1.5 ≤ (X0DG) / (X1DG) ≤2 .5

This will achieve net (an overall Thevenin Equivalent) Positive and Zero Sequence impedance at any point on the feeder with any or all DG sources and utility sources in-service of:

2 < X0 / X1 < 3 and R0 / X1 < 0.4; or

For DG Facilities with an Inverter Interface:

X0DG = 0.6 ±10% p.u. and X0DG / R0DG ≥ 4

where 1 p.u. is based on kV 2 / MVA Ω:1) 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; or2) the MVA and high side kV rating of the DGIT for NGR sizing.3) DG interface transformer (DGIT) MVA rating is assumed to be approximately equal to

the generation capacity4) for inverter based interface the “0.6” is a conservative approximation

7.0 ConclusionsAn ineffectively grounded DG interface can cause over-voltages that can damage utility equipment and customer loads. Effective grounding is of the utmost important because with a solidly grounded interface, the utility’s ground protection is jeopardized and if the interface is ungrounded, then there is a TOV concern. During SLG faults on the distribution feeder operating with ungrounded DG interface, TOV can occur even before the DG islands. Moderation of TOV by loads or transformer saturation is not significant enough to be effective. Effective grounding of DG facility interface can be accomplished by either connecting an appropriately sized grounding transformer on the HV side of the ungrounded winding of the DG interface transformer, or by selecting the DG interface transformer with Star- imp-gnd (HV) and delta (LV) winding configuration with an adequately sized “neutral grounding reactor” (NGR).

8.0 Bibliography8.1 ITIC (CBEMA) curve8.2 IEEE Std C62.11-1993, IEEE Standard for Metal-Oxide Surge Arresters for Alternating Current

Power Circuits (>1 kV)8.3 IEEE Std C62.92.4-1991, IEEE Guide for the Application of Neutral Grounding in Electrical Utility

Systems, Part IV—Distribution8.4 Kinectrics Inc. Report: K-013802-001-RA-0001-R038.5 Distributed Generation Technical Interconnection Requirements Interconnections At Voltages 50kv

And Below - HYDRO ONE NETWORKS INC.


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Example of TOV Causing TOV & Mitigation Using a High Voltage Grounding Transformer (HVGT)See Figure 1 below. Transformer winding configuration at the DR impacts TOV and therefore may be used to mitigate or eliminate a TOV issue. To provide an example of how TOV arises and how it may be controlled, it was assumed that the generation step-up transformer (GSU) configuration is grounded-wye: grounded-wye (Yg:Yg). With this winding configuration, and a solidly grounded distributed generator, there will be no TOV issue. However, it is common practice with many types of generators such as a synchronous generator, to add an impedance between the generator neutral and ground to limit fault current for ground faults within the machine or near its terminals. If a ground fault occurs on the Area EPS, or on the low voltage system, ground current will flow through the neutral ground impedance which in turn will produce a neutral voltage shift at the generator. This voltage will be added vectorially to the generator output phase voltages. The net result is that the un-faulted phase voltage increases with respect to ground and could achieve a value as high as 1.7321 PU. The Yg:Yg transformer will pass this onto the primary. Utility and customer equipment connected to the system will be exposed to this TOV and damage could result.

ORIntertieRelay

GT DR1

PCCArea EPS

HVBR LVBR

Figure 1: DG Using a HVGT to Mitigate TOV

To mitigate the TOV a zig-zag (ZZ) or grounded-wye:delta (Yg:D) grounding transformer may be used. Both devices are functionally equivalent. The grounding transformer presents a high impedance to positive and negative sequence voltages and a low impedance to zero sequence voltage. It therefore acts as a zero sequence voltage shunt to reduce zero sequence voltage and the TOV. Referring to Figure 1 below, the grounding transformer was placed on the high voltage side so it is a high voltage grounding transformer (HVGT). It could also have been placed on the low voltage side in parallel with DR1. The required zero sequence impedance of the HVGT to maintain the TOV within acceptable levels, without unduly desensitizing the utility ground fault protection, is determined by a fault study or connection impact study. When the impedance value is known, a HVGT with the required impedance must be designed for a short term rating to withstand the fault current and the duration of the fault, and a long term or steady state rating to withstand the normal unbalance on the distribution system. It must remain connected under these two conditions to reduce the TOV. Unbalance on the distribution system, especially on long heavily load feeders, can be come in the form of angular unbalance, where the voltage phasors are no longer 120° apart, and magnitude unbalance. The net result will be some zero sequence voltage present at the PCC. A typical value of zero sequence voltage, V0, is 2% of nominal. It is recommended that the HVGT be designed to withstand a minimum of 4% V0 and remain connected. The fault study will also provide the fault current and duration of the fault which is the other specification for the design of the HVGT.


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Referring to Figure 1, the interconnection protection is designed to protect the distribution system and also protect the grounding bank. For a fault on the distribution system or within the DR facility it will trip both the high voltage circuit breaker, HVCB, and the low voltage circuit breaker, LVCB. The DG protection should also be designed to detect faults within the facility up to the PCC. The HVGT neutral CT provides a current signal to detect ground faults on the Area EPS or the DR site. It also provides a current signal to protect the grounding bank from damage for a fault that fails to clear within acceptable time limits or an abnormal steady state condition on the distribution system where the zero sequence voltage is excessive. It is recommended that an inverse time overcurrent element be used for this function with a minimum pickup of 1 PU of the HVGT rated current.

It should be noted with reference to Figure 1, that the grounding transformer could be placed on the low voltage side in parallel with the generator to mitigate the TOV. Most utilities require the grounding bank to be disconnected from the Area EPS when the DR is not on line so it will not unnecessarily desensitize the Area EPS ground fault protection. If the grounding bank is on the high voltage side, then HVCB is required to disconnect the grounding bank. If it is on the low voltage side, HVCB can be eliminated since the LVCB will perform this function.

The Yg:D HVGT can be developed using standard single phase distribution transformers. This may require specific % impedance values to obtain the desired zero sequence impedance value, but as long as this value is within the normal design range of the transformer manufacturer, experience has shown that this can be an economic option. Distribution transformers are robust devices. IEEE 57.109 indicates that they can withstand 25X rated current for 2 seconds. A fault of this magnitude should be cleared in under 0.5 seconds so short term rating should not be an issue.

Case Study.A 2MW solar farm is connecting to a 27.6/16 kV four wire feeder. The Area EPS provided the following formulae to calculate the value of X0 when an inverter based is connecting to the four wire system:

X0 = (V2L-L/DR MVA) x 0.6

X0 = (27.62/2MVA) x 0.6X0 = 228.6 ohms.

The tolerance for this value is ±10%.citation: Hydro One Distributed Generation Technical Interconnection Requirements DT-10-015 Rev. 2, June 2011, page 151.


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Design an HVGT for this site using standard distribution transformers. Select a relay, a protection element and provide the minimum pickup set point for the inverse time overcurrent protection for this application and verify that it will protect the HVGT.

Use 3x50 kVA standard distribution transformers in a wye-grounded to delta grounding bank.. At 16 kV, the full load current will be 50 kVA/16 kV= 3.125 A. If the % Z of the transformer was 5%, the short circuit current would be 100/5 X 3.125A = 62.5 A. At 16 kV this would be 16 kV/62.5 A = 256 ohms which is too high. Try 4.5%. The short circuit current would be 100/4.5 x 3.125 A = 69.44 A. At 16 kV this would be 16 kV/69.44 A = 230 ohms. This impedance value is within the tolerance level.

The current flowing the neutral connection of the Yg:D bank will be 3I0. At rated current this will be 3 x 3.125 A = 9.375 A. This will be the value of current that would flow if V 0 reached 4.5% of nominal. Set this as the minimum pickup setting for the inverse time overcurrent protection. This will provide protection against steady state V 0.

Select an inverse time overcurrent element and verify that this element will protect the HVGT at 2PU and 10PU fault current.

Use the SEL 651R2 Timed Overcurrent ElementRefer to Section 9.5, page 413 of the Instruction ManualUse the U2 CurveThe formulae for the operate time Tp is:Tp = TD x ((0.180 + (5.95/(M2-1)))

1. At 2PU the operate time would be 32. 4 seconds. The minimum time before damage would occur at this point damage curve is 1800 secs.

2. At 10PU the operate time would be 3.6 seconds. The minimum time before damage would occur at this point damage curve is 12.5 seconds.

Therefore, the inverse overcurrent element will protect the HVGT


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Appendix 1 of Annex G. Temporary Over-Voltages on Distribution Systems Associated with the Connection of Distributed Generation1.0 Summary

The classification of Temporary Over-Voltages (TOV) as distinct from transient over-voltages is due to its longer duration and the fact that the responses of power network insulation and surge arresters to their wave shapes are different.

TOV associated with single line to ground (SLG) fault is not a concern on “three-phase, three-wire” distribution system, because insulation there is suitable for phase to phase voltages which are not affected. Subsequently, customer low voltage (LV) equipment is therefore not affected by TOV.

On three-phase, four-wire distribution system the surge arrestors and customer LV equipment particularly exhibiting sensitivity to dielectric stresses, such as electronic equipment or those employing directly coupled solid-state switching devices (e.g. variable speed motor drives) may be at risk of incurring failures if TOV exceeds 120% of the normal phase-to-ground voltage.

The TOV at different locations along the distribution feeder is function of both the design of utility’s ground sources at the Transformer Station, and the additional cumulative effect of the X0/X1 ratio of the feeder conductors to the fault location.

ITIC (CBEMA) CURVE may be EXCEEDED in many distribution feeders with or without DGs connected. PROHIBITED REGION. (reference 8.1)

o Voltage > 120% of Nominal Voltage for period 3ms to 0.5 so Voltage > 110% of Nominal Voltage for period > 0.5 s

For SLG faults, DG interface transformer with high voltage side Delta or ungrounded Star connected DGs may cause significant over-voltages to Single Phase Loads even before feeder and/or DG circuit breaker opens.(section 5.3.1)

Distribution feeder load has to exceed DG capacity by about a factor of 5-10 times, depending on how much of it is supplied over phase-to-ground connected transformers as well as on its power factor, to be effective in moderating over-voltages on the un-faulted phases to the levels generally expected in effectively grounded systems. (section 5.4)

Transformer saturation does not limit the peak over-voltages. Saturation is only moderately effective in reducing the rms overvoltage duty. This means that equipment sensitive to dielectric stresses such as solid-state devices is vulnerable. (section 5.4

Prevention of TOV at the grass root, i.e. at the source, is better than reacting after its occurrence. The effective grounding of the DG interface is the safest way to ensure that the TOV is prevented at the source itself. (section 6.3)

Other probable over-voltage phenomena, not discussed here, but should be considered are “series resonance” (between the generator and power factor correction capacitor banks connected on the distribution feeder) and “ferro-resonance” (interaction between the non-linear magnetizing reactance of transformers and other magnetic devices and system capacitance.)


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2.0 IntroductionThe interconnection of Distributed Generation (DG) to the utility distribution system adds a complication to the design as well as to the normal operation of utility systems. Both the utility and DG owner must ensure that the DG facility interconnection is designed to provide safe, reliable, economical operation, and jointly ensure that the DG operation:

a) does not harm or damage the utility equipment; b) does not cause problems for other utility customers; andc) the safety of personnel and the public is not jeopardized

There are numerous DG impacts on the utility system such as voltage regulation, thermal integrity, increase in fault current level, protection desensitization, and sympathetic trips etc. These concerns must be addressed in the design and operation of the DG interface. One unique concern which could have serious consequences, and must not be over-looked, is the “Ground fault Temporary Over-Voltages”.

The “Temporary Over-Voltages” (TOV) in the distribution system is a fundamental frequency over voltage. In this paper, the discussion will be limited to TOV associated with ground faults, particularly single line to ground (SLG) faults occurring on distribution feeders, before and after DG is connected. The TOV causes, acceptable limits, moderation, impacts on equipment, prevention etc., will also be discussed.

3.0 Temporary and Transient Over-VoltagesThere are two components of overvoltage in electrical systems when a system ground fault occurs, or when a circuit breaker or a switch operates in clearing the ground fault. One of these is the temporary overvoltage or fundamental frequency overvoltage, and the second is the natural frequency voltage, usually of short duration, that is superimposed upon the temporary overvoltage. Since total voltages are of greater interest, the sum of the temporary overvoltage and the natural frequency voltage is commonly used and termed as the transient voltage. The Temporary Over Voltage (TOV) is defined as a fundamental frequency oscillatory overvoltage, associated with switching or faults (for example, load rejection, single-phase faults) and/or nonlinearities (ferro-resonance effects, harmonics), of relatively long duration, which is un-damped or slightly damped. Temporary over-voltages can last for several seconds, whereas transient over-voltages have a duration of a few milliseconds.The level of TOV associated with single-phase faults is directly related to the Coefficient of grounding (COG) and the Earth Fault Fact (EFF).

COG is defined as the 100% x ELG/ELL.

ELG is the highest rms line-to-ground power frequency voltage on a sound phase, at a selected location, during a fault to earth affecting one or more phases. ELL is the line-to-line power-frequency voltage that would be obtained, at the selected location, with the fault removed. (Reference 8.2

EFF is more directly correlated to TOV associated with single-phase faults. It is similar to COG but is defined as: At a particular location on a three-phase system, for a given system configuration, the EFF is the ratio of the highest rms line-to-ground power-frequency voltage on a sound phase during a fault to ground (affecting one or more phases at any point) to the rms power-frequency voltage that would be obtained at the selected location with the fault removed: EFF = √3 COG/100


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Temporary over-voltages (sustained over-voltages) differ from transient over-voltages in that they last for longer durations, typically from a few cycles to a few seconds.They take the form of un-damped or slightly damped oscillations at a frequency equal or close to the power frequency.The classification of temporary over-voltages as distinct from transient over-voltages is mainly due to the fact that the responses of power network insulation and surge arresters to their wave shapes are different.

4.0 Temporary Overvoltage (TOV) limitsThere are different TOV limitations for 3-wire and 4-wire distribution systems. These differences can be summarized as following:

4.1 Three – wire unigrounded distribution system4.11. The grounding of most “three–phase, three–wire” distribution system is designed close to

the “effectively grounded” threshold, where Coefficient Of Grounding (COG) ≤ 0.8, and Earth Fault Factor (EFF) ≤ 1.39. This limits the TOV to 139% of the pre-fault voltage (reference 8.3). Allowing for 5% system voltage regulation, the maximum temporary overvoltage is then 144 %.

4.1.2 Surge arresters most commonly used on “three-wire” system can tolerate up to 181% TOV for 100ms, 171% TOV for 1 second, and 149% continuously.

4.1.3 Customer distribution transformer windings are connected phase-to-phase. Therefore phase-ground (zero sequence) voltage on the HV side of the distribution transformer is not transformed to the LV side and the customer LV equipment is not affected by TOV on the distribution system.

4.2 Four – wire multi-grounded distribution system4.2.1 The grounding of typical “three-phase, four-wire” system such as 4.16 kV, 8.32 kV,

12.48kV, 25kV and 27.6 kV distribution systems are designed below the “effectively grounded” threshold. The COG for ideal 4-wire Dx is approximately 0.69. That limits TOV to about 120% of the pre-fault voltage. Allowing for 5% system voltage regulation then the maximum temporary overvoltage is 125%. However, it will be seen in the later section (Figure4) that the TOV at the feeder-end of long radial feeders can approach 130%.

4.2.2 Surge arresters generally used on “four-wire” distribution system tolerate up to 156% TOV for 100ms, 147% TOV for 1 second, and 128% continuously.

4.3.3 Customer distribution transformer windings are connected phase-to-ground, so these transformers and customer LV equipment are affected by TOV.

4.2.4 The Information Technology Industry Council (ITIC), formerly known as the Computer and Business Equipment Manufacturers Association (CEBMA) published a curve that describes the ac input voltage envelope that electronic equipment can tolerate. According to the ITIC curve, voltages greater than 120% for durations from 3 ms to 0.5 second and greater than 110% for durations greater than 0.5 second are in the prohibited region.


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4.2.5 It has been shown that for feeder-end SLG faults on “four-wire” distribution systems, the TOV voltages will move slightly into the prohibited regions of the ITIC curve. For example any fault beyond approximately 5 km will result in a TOV greater than 120% (see Figure 4) and may approach 130% under certain conditions (see Figure 10).

4.2.6 130% TOV is a more realistic expectation for utility 4-wire Distribution Systems and is

within the limits that IEEE suggests for the neutral grounding of 4-wire distribution systems.

5.0 Important Aspects of TOV On Single Line-to-Ground Faults

1. 5.1 TOV Phenomenon (phasor analysis)When a single-line-to-ground (SLG) fault occurs on the Distribution System, the voltage on the un-faulted phases will change, depending on the net positive and negative sequence impedances. Assuming the fault on” A” phase (or “Red” phase), the voltages on the un-faulted phases “B” (“White” phase) and “C” (“Blue” phase) can be calculated by the equations shown below. Although, commercial power system modeling software is best used to assess TOV values, these simplified equations serve to illustrate the effects of positive, negative and zero sequence impedances on TOV. Note that if the value of Z0 approaches infinity, the voltages on the un-faulted phases approaches 1.73 times the pre-fault voltage (equations [8] and [9]).

Figure 17

Basic equationsx + j y r∠ angle

1 = 1 + j 0 1∠0 ºa = -0.5 + j 0.866 1∠120 º -------- (1)a2 = -0.5 - j 0.8661∠240 º -------- (2)1 + a + a2 = 0a + a2 = -1 -------- (3)Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 145

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I1 = I2 = I0 For Line to Ground FaultsI0 = Vf / (Z1 + Z2 + Z0 + 3Zf) I0 = Vf / (2Z1 + Z0 + 3Zf) ------- (4)

(as Z1 = Z2 for passive devices lines & transformers)V1 = Vf - I1 Z1= Vf - I0 Z1 ------- (5)V2 = - I2 Z2 = - I0 Z2 ------- (6)V0 = - I0 Z0 ------- (7)

The voltage on un-faulted phases “b” & “c” can be calculated by;

Vb = a2 V1 + a V2 + V0

= a2 (Vf - I0 Z1) + a (- I0 Z2) + (- I0 Z0) --- substituting (5), (6) & (7)

= a2 Vf - a2 I0 Z1 - a I0 Z2 - I0 Z0

= a2 Vf - a2 I0 Z1 - a I0 Z1 - I0 Z0 --- as Z1= Z2

= a2 Vf - I0 (a2 Z1 + a Z1 + Z0)

= a2 Vf - I0 (Z1(a2 + a) – I0 Z0

= a2 Vf - I0 (Z1(- 1) –I0Z0 --- substituting (5)

= a2 Vf - I0 (Z0 -Z1)

= a2 Vf - Vf (Z0 - Z1) / (2Z1 + Z0 + 3Zf) --- substituting (4)

= Vf [a2 - (Z0 - Z1) / (2Z1 + Z0 + 3Zf)]

= Vf [a2 - ((Z0 / Z1) - 1) / ((Z0 + 3Zf) / Z1)+ 2] -dividing num/denom by Z1

= Vf [(-0.5 - j 0.866) - ((Z0) / Z1) - 1) / ((Z0 + 3Zf) / Z1)+ 2]--- substitution (2)

= Vf [(-0.5 - j 0.866) - ((X0 / X1) - 1) / ((X0 / X1)+ 2)] --- neglecting resistance & Zf

= Vf (-0.5 – ((X0 / X1) - 1) / ((X0 /X1)+ 2) - j 0.866

Real part = -0.5 – ((X0 / X1) - 1) / ((X0 / X1)+ 2) or – [0.5 + ((X0 / X1) - 1) / ((X0 / X1)+ 2)]

Imaginary part = [- j 0.866]

Vb= Vf [(0.866 2 + (0.5 + ((X0 / X1) - 1) / ((X0 / X1)+ 2))2)1/2]

= Vf [(0.866 2 + (0.5 + (1)) 2)1/2] ---- X0 ≈ ∞

Vb= Vf [ 1.732 ] ----- (8)

Next Vccan be equated similarly by substituting relevant equations from 1 to 7 in expression V c = a V1

+ a2 V2 + V0; Vc= Vf [ 1.732 ] ----- (9)


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5.2 TOV level on the distribution feeder without DGThe TOV at different locations along the distribution feeder is a function of both, design of the utility’s ground sources at the Transformer Stations, and the additional cumulative effect of the X0/X1 ratio of the feeder conductors to the fault location. Thus, the TOV at a particular location is primarily determined by the net X0/X1 ratios prevailing at that location as shown in Figure 2.


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Figure 18 (TOV on un-faulted phases without DG)

- Vb =Vc= Vf [(0.8662+(0.5+((X0/X1-1)/(X0/X1+2))2)1/2)]- This is an approximation formula neglecting resistances and fault resistances- Source voltage Vf = 1.05 pu for graph

Depending upon the number of transformers in service there are usually maximum and minimum source conditions at a Transformer Station (TS). Typical X0/X1 ratios for a “four-wire” 27.6 kV TS that is effectively grounded are shown in Figure 3 below (TS max and TS min).


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Figure 19 (TOV on un-faulted phases, expanded and with max/min utility source-without DG)

- The X0/X1 ratio values shown here at TS for max and min source are 0.97 and 1.41 which would result in TOV levels of approximately 104% to 112%.

- These values will vary from station to station depending on the strength of the Transmission System, the impedance of the TS transformers and the reactance of the neutral grounding.

- For faults on the distribution system, particularly at distant feeder-end locations far from the TS, the cumulative impedance of the feeder from the TS becomes much higher than the utility’s source impedance at the TS. The higher feeder-end fault impedance results in a lower fault level and an X0/X1 ratio that approaches that of the feeder.

- Typical conductors used in the distribution system have X0/X1 ratios of 2.71 to 3.02 as shown in Table 1. These ratios are generally higher than the utility sources so the TOV for faults at the feeder-end tend to be higher than those at the TS.

- The characteristics of a 336 ACSR conductor are used in Figure 3. The X0/X1 ratio values shown here at feeder end for max and min source are 2.60 and 2.82 which would result in TOV levels of approximately 127% to 129%.


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Table 1 (Typical conductor details)

Conductor(O/H)

R (+) jX (+) Z1 mag

Z1

angle jX (0) Z0

magZ0

angle Z0/ Z1 X0/ X1

Ω/km Ω/km Ω/km degree Ω/km Ω degree556ACSR-3-44 0.1021 0.4037 0.4164 75.8 º 1.0946 1.1290 75.8 º 2.71 2.71336AL-4-27.6 0.1691 0.4182 0.4511 68.0 º 1.1899 1.2701 69.5 º 2.82 2.8530ACSR-4-27.6 0.3481 0.4685 0.5837 53.4 º 1.3224 1.4973 62.0 º 2.57 2.82

# 1/0 ACSR 0.5523 0.4852 0.7352 41.3 º 1.4641 1.7532 56.6 º 2.38 3.02

Figure 20 (TOV increases with the distance of the SLG fault from the utility Source).

- Minimum source, fault resistance RF = 0 ohms- TOV is 113% at TS, which corresponds to X0/X1 = 1.41 - TOV is 128% at feeder-end where X0/X1 = 2.60, which approaches feeder conductor’s X0/X1

value


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5.3 TOV on distribution feeder with DGWhen DG is connected, the net positive, negative and zero sequence impedances change, which causes a change in TOV during SLG faults. Care must be taken to ensure that TOV levels are not increased to a level where the ratings of the surge arresters, distribution transformers and customer LV equipment will be exceeded.

5.3.1 TOV – when the utility and the DG facility both are contributing to the fault respectively

TOV during this condition is often overlooked, but there could be TOV for the duration up to 150 ms or more. Depending upon; a) the feeder protection philosophy practiced by the utility, b) the magnitude of the fault currents seen at the feeder protections, and c) capability of the DG to sense and timely clear the ground faults on the distribution feeder, there will be a substantial duration of time, for which, the SLG fault will be jointly fed by utility and DG. When the DG is connected through an interface transformer with an ungrounded HV winding, it is often assumed that it does not alter TOV as there will be no change in net zero sequence impedance. However, by connection of the DG, the net positive sequence impedance reduces and thus the ratio of X0/X1 increases which causes TOV.Figure 6 shows how TOV can exceed 135% for large ungrounded DGs located just a few km from the TS. Any means of rapidly detecting the overvoltage and interrupting the DG source might represent a solution, but violation of ITIC curve and subsequent over-voltages cannot be prevented. Thus, even use of a fast Transfer Trip (TT) to disconnect the DG from the distribution system before the utility source is disconnected will not help in reducing these high voltages. Only a reduction in the net zero sequence impedance can be effective in reducing these voltages which is shown later in section 5.7.


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Figure 21 (TOV for feeder-end SLG Faults, Utility + DG)

- For minimum source, fault resistance RF = 0 ohms- TOV is 148% at feeder-end for DG located at 31.5 km where net X0/X1 is 5.65


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Figure 22 (TOV for SLG Faults at PCC, Utility + DG)

- For minimum source, fault resistance RF = 0 ohms- TOV is 158% at PCC for DG located at 31.5 km where net X0/X1 is 7.69

2. 5.3.2 TOV – DG in islanded condition TOV in an islanded section of the distribution feeder can potentially persist, when the utility source is disconnected by the opening of its interrupting device, such as circuit breaker or in-line re-closer, and the DG facility is still connected keeping the faulted section of the feeder energized. If the DG with high zero sequence impedance is connected to the distribution feeder and islands from the utility source, TOV can reach maximum level of 173% in that island. Allowing for 5% system voltage variation, the maximum phase –ground voltage can reach 182% (Figure 7). This will be the case whenever a Delta or ungrounded Star winding connection is used on HV side of the DG interface transformer (DGIT). Depending on the grounding of DGIT and generator neutrals, the DG sources may have high net zero sequence impedances even when a grounded wye (Star-gnd/star-gnd) connection is used as the DG interface transformer.

Figure 23 (Voltage vectors for feeder-end SLG fault at (ungrounded DG island)


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- SLG fault at “a” phase- Voltages on the un-faulted phases are displaced by the maximum amount (182%)- |Va| = 0 kV, |Vb| = 28.98 kV (181.9%), |Vc| = 28.98 kV (181.9%)- These high voltages are essentially the same value along the entire feeder

3. 5.4 Moderation due to Connected LoadsDuring SLG fault when the utility source and the DG are still connected, the feeder loads being of much higher impedance than utility source, will not have any significant influence in moderating over-voltages and should not be considered.

For a DG islanded condition, by developing a sequence network connection, the resulting zero-sequence voltage can be obtained by a simple voltage divider exercise:

Zero-sequence voltages:

Negative-sequence voltages:


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Based on these equations the voltages on the un-faulted (healthy) phase can be calculated in similar way as shown in section Error: Reference source not found.

At low 3-Ø load levels, near the DG capacity, the zero-sequence voltage is nearly 1 p.u, indicating a full neutral potential shift, and the voltage on the un-faulted phases approaches the line-to-line rating. At higher loadings, over-voltages are moderated due to the regulation drop through the interface transformer. Thus, if feeder loading is significantly higher than the DG capacity, the over-voltages will be moderated, as expected, but needs to be several times more than the 3-phase DG rating (not its output). The loads with lagging power factor can yield further moderation. However, the 3- Ø loads, even if they are comparatively large, may be effective only for a short duration because of substantially lower voltage at the faulted phase.

Now the presence of line to neutral connected loads will also have a moderating influence. Practically where the DG capacity matches or is close to feeder loading, only a little moderation can be expected. Figure 8 shows that, if all of the feeder load was connected line-to-ground and operated at 0.95 power factor respectively, it would need to be almost 8 times the DG capacity to reduce over-voltages to those expected on effectively grounded systems It should be noted that, the feeder load has to exceed the DG capacity by about a factor of 5-10 times, depending on how much of it is supplied over phase-to-ground connected transformers as well as on its power factor, to be effective in moderating over-voltages on the un-faulted phases to the levels generally expected in effectively grounded systems.


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Figure 24 (TOV moderation if all of the feeder load is connected phase-to-ground, with different power factors).

5.5 Moderation due to Transformer SaturationIt is evident from earlier sections that there will be TOV for SLG faults. Distribution transformers will be subjected to these over-voltages. Depending upon core magnetizing characteristics the distribution transformers will saturate. Transformer saturation in principle can affect primary and secondary voltages.

Time-domain simulations are required to precisely analyze the impact of transformer saturation, because the nonlinear magnetization characteristics have to be taken into account. However, conceptually it can be analyzed as following.5.5.1 Primary (feeder) overvoltage

It is generally assumed that transformer saturation limits the neutral-shift overvoltage to a magnitude much less severe than the ideal phasor calculations shown in an earlier section. However, the load transformer ratings need to be much higher than the DG capacity for reactive loading to be effective in moderating over-voltages. Also the duration over the power-frequency cycle over which the core enters saturation is reduced. Next, the flux is in quadrature with the phase voltage, such that peak core flux does not coincide with peak over-voltage.


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Computer simulations show that transformer saturation results in severe distortion of the open-phase voltage to ground, but does not significantly reduce the crest voltage. (reference 8.4)

5.5.2 Secondary overvoltageTransformer core magnetizing impedance Zm tends to be orders of magnitude larger than the leakage. Thus, the primary and secondary voltages are nearly equal to their respective rating.

However, during core saturation, which occurs cyclically over a portion of the power frequency cycle in the event of a temporary overvoltage condition, Zm is reduced briefly, in the range of only an order of magnitude higher than the leakage impedance. The instantaneous value of secondary voltage Vs is therefore reduced by a regulation drop only. The simulations reveal that transformer saturation is ineffective in moderating the peak overvoltage, though perhaps reducing its rms value modestly.

5.6 Effect of fault resistance Fault resistance also can have an effect on TOV. For high fault resistances, the TOV will be reduced in both of the healthy phases. However, for low levels of fault resistance, there is a small range over which the TOV will be increased in one of the healthy phases. For the fault resistances, that range from 7 to 13 ohms, over which the TOV can increase to about 130% in “b” phase for SLG at “a” phase. (Figure 9). Figure 10shows how the TOV increases with the distance of the SLG fault from the utility Source, when the fault resistance is 10 ohms.


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Figure 25 (Voltage vectors for feeder-end 10 Ω SLG fault, utility only – no DG)

- Voltages on the un-faulted phases are partially displaced- |Va| = 4.34 kV (27.3%), |Vb| = 20.66 kV (129.7%), |Vc| = 18.61 kV (116.8%)

- |Va| is non-zero and |Vb| higher magnitude than |Vc| because of the effects of the fault resistance


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Figure 26 (Effect of Fault Resistance on TOV, SLG fault at 50km, utility only - no DG)

- For SLG fault at 50km, the maximum TOV in one of the healthy phases (for 556ACSR conductor) is when the fault resistance is around 15Ω

5.7 Effect of the resistive component of the utility system and the DG facility on TOV

5.7.1 Resistive component of the utility system

Assuming X1 constant: (although the utility station transformer’s tap position of under load tap changer should be considered in X0 / X1 ratio)For an increase in R0 the TOV increases and the system becomes un-effectively grounded if the ratio R0 / X1 is > 1. (However, the value of R0 needs to impractically high with respect of X1). For increase in the system R1 (feeder R1 remaining the same), the TOV increases in one of the healthy phases and decreases in the other healthy phase. An increase in feeder R 1

(system R1 remaining the same), the TOV increases marginally higher than the earlier case (system R1 increase) in one of the healthy phases and also decreases marginally lower than the earlier case, in the other healthy phase. However, the change in TOV is not significant with respect to minor changes in the resistive component. For a 10 times increase in the resistive component, the change in


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TOV (an increase in one healthy phase and a decrease in another) is expected to be around 5%.

5.7.2 Resistive component of the DG facility

1. The effect of R1 can be expected to be similar as discussed in 5.7.1, but the DG facility’s R0 should be given due consideration when selecting the interface transformer’s neutral grounding. Besides the heating effects, the “neutral grounding resistor” will have significantly higher TOV in one of the healthy phases in comparison to the same value of “neutral grounding reactance”. Neutral grounding reactance (NGR) is discussed in next section under 6.3.


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Annex H (Informative) -- Voltage and Frequency Trip Coordination with Area EPS

With more aggregate DR capacity, their tripping on voltage or frequency excursions may result in a significant loss of generation capacity, and in turn lead to or worsen a cascading emergency in the Area EPS. For that reason, voltage and frequency trip settings of the DR should be coordinated with the Area EPS. These should be developed from contingency studies of the area EPS with aggregated DR production, and these studies should be performed at the interconnection planning stages.

Contingency analysis should also be done in operational time frames that consider status of the DR and supply-demand balances in potential islands. Coordination of the Area EPS with DR should be considered for remedial action schemes, restoration of loads, and re-connection of DR.

Operational coordination may require the use of more complicated and expensive methods for detecting faults and unintended islands on the Area EPS. In the absence of operational coordination, default voltage and frequency trip settings from Std. 1547 may be used. However, these default settings may adversely impact reliability of the bulk power system, may lead to the need for increased reserve generation on the bulk power system, or may lead to increased load shedding after a disturbance on the bulk power system. Therefore, Area EPS operators should weigh the costs and benefits of using default vs. coordinated settings.

Figures 27 and 28 show that default Std. 1547 frequency and voltage trip settings may result in loss of DR capacity during frequency or voltage excursions that are allowable in the Area EPS. Figure 28 compares the default Std. 1547 voltage trip settings to recently proposed North American criteria for voltage ride-through. The default voltage trip settings allow riding through a short period of zero voltage, which may limit nuisance tripping of DR during faults on adjacent circuits or the nearby transmission system. The default settings do not require DR to ride through any period of zero voltage. After a period of zero voltage, the recovery voltage transient may cause a trip by the default settings, when they would not have under some of the ride-through criteria plotted in Figure 28.

Some jurisdictions now require DR to ride through zero-voltage faults on medium-voltage distribution systems; Figure 29 provides one example. Ride through is not required if the recovery voltage drops below 30% after 0.15 seconds. If the recovery voltage falls between Limit 1 and Limit 2, but still above 30%, tripping may be allowed in coordination with the local EPS. Also, tripping may be allowed if re-connection can occur within 2 seconds. This jurisdiction distinguishes between inverter-coupled DR and other DR interconnections; IEEE 1547 makes no such distinction.

Increasing the maximum clearing time is not equivalent to implementing or increasing the ride-through time. Clearing time is equal to relaying time plus breaker time. In IEEE 1547, this may range from “as fast as possible” up to the maximum time specified in the standard. On the other hand, ride-through capability means that during periods of abnormal voltage or frequency, the DR does not cease to energize the Area EPS, except to comply with clauses 4.2.1, 4.2.2 and 4.4.1 of IEEE 1547, and in consideration of the DR operating capabilities. The operating parameters should be specified when a ride-through function is provided. The ride-through time is equivalent to relaying time, and the clearing time is equivalent to relaying time plus breaker time. Therefore, ride-through time will be less than the clearing time. When ride-through is implemented, there should be a margin in both time and magnitude between the ride-through region and the must-trip region. Figure 30 provides an example of coordinated ride-through and must-trip requirements.

Ride-through requirements change the way DR operates, for example, the unit may become totally reactive during low-voltage conditions. Ride-through will probably conflict with detection of unintended islands, especially for


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inverters, which cannot reliably use overcurrent sensing to detect an island. Transfer trip schemes may be used for islanding detection, but these are more expensive and complicated as the number of DR units increases.

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Small-DROperating Area in IEEE Std. 1547 ( ≤ 30 kW)

Figure 27 - Example Area EPS Load Shedding vs. 1547-2003 Default Frequency Trip Settings, DR ≤ 30 kW


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Figure 28 - Example North American Transmission Voltage Ride-through Criteria vs. 1547-2003 Default Settings


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Figure 30 – A Voltage Ride-through Region Coordinated with Must-Disconnect Region


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Annex I (Informative) -- Response of Non-Traditional Generators under Fault Conditions

InvertersInverters are used with PV generation, full-conversion wind turbines, and certain micro-turbine designs to convert power from either dc or from another ac source, typically variable, frequency and voltage source. Most grid connected inverters today use voltage-source converters with current limitation and closed loop current controls. There are two characteristics of voltage source converters that are critical to their fault current behavior. The first is that the power electronic devices used in these converters, typically IGBTs, are extremely sensitive to currents exceeding a certain threshold. Exceeding these current levels can cause near instantaneous failure of these devices. When the power electronic devices are applied in a practical and economic way, this failure current is on the order of twice the rated current. A power electronic failure appears as an open circuit. The second characteristic of inverters is that they can be controlled by very high bandwidth controls. For grid-connected inverter applications, the inverter is typically controlled to be a constant-current source. This controllability of the current is essential in order to protect the power electronic devices from fault current damage. The bandwidth of the current regulators can be in the hundreds of Hz, meaning that a grid disturbance, even a fault, will cause the current to deviate from the current regulator’s reference value for only a few milliseconds. Such brief deviations in current are typically not relevant to protection coordination, so for all practical purposes, the inverter appears as a constant current source.

The current regulator reference, however, may be set by a higher level control. One such control can be a constant power regulator. When the voltage drops during a fault, the power regulator may raise the current reference in an attempt to maintain constant power output. However, to avoid excessive thermal duty on the inverter equipment, including the semiconductor devices, the maximum current regulator reference is limited. A typical limit is on the order of 1.3 times rated current. Quite often, the higher level controls setting the current reference are much slower in response than the current regulator itself. Therefore, the current may increase over a number of cycles following fault application as the power regulator responds.

Three-phase inverters are often designed to inject only a positive sequence current. They will develop the negative sequence voltage necessary to oppose the flow of negative sequence current during unbalanced faults. This ability to oppose negative sequence current may be limited by inverter capabilities, and thus the response to unbalanced faults may be nonlinear, with complete blocking of negative sequence currents for less severe faults, and possibly some negative sequence flow during more severe faults.

Inverters as the interface medium for special applications such as energy storage systems, may be designed to provide a higher level of transient capacity for a short period. An example of this is an energy storage unit that can provide 250% of its rated capacity for 5 seconds for load following purposes. The short term rating of such inverters should be considered during the design phase and for fault current calculations.

Doubly-Fed GeneratorsCopyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 165

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Doubly-fed asynchronous generators (DFG) are used in wind generation to provide variable speed operation over a wide range (typically ±30% of synchronous speed), and highly responsive reactive power and ac voltage regulation capabilities. These machines are also commonly called doubly-fed “induction” generators (DFIG). However their performance capabilities and fundamentals of operation are substantially different than any induction machine. The complexity of these machines necessitates a thorough discussion of their principles of operation, before addressing their fault behavior.

The topology of a typical DFG wind generator is shown in Figure 1.

Figure 1: Topology of a typical doubly-fed (Type III) wind generator.

DFG Concept of OperationDFG machines have three-phase ac rotor windings with slip-rings allowing the rotor to be “excited” by an external power converter. The stator of the DFG is directly connected to the electric grid. The three phase rotor windings of the DFG are connected to a power electronic converter which provides the variable magnitude and the frequency of the rotor current. The other side of this back-to-back ac-dc-ac converter is connected to the grid. In terms of excitation, a DFG is similar to a synchronous machine, however the excitation applied to the rotor is ac with variable frequency and reversible phase rotation.

The application of an AC excitation causes an apparent rotation of the rotor’s magnetic field, relative to rotation of the rotor. This apparent rotation adds to, or subtracts from (in the case of negative sequence excitation applied to the rotor) the physical rotation of the rotor. The stator field angular rotation, s is the sum of the mechanical angular speed rotation of rotor, m and the rotor field voltage frequency r as shown in Equation 1. The ps and pr are the stator and rotor pole numbers.

ωs

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ωr

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(1)When the wind turbine is operating below the synchronous speed (sub-synchronous speed), the excitation applied creates apparent field rotation in the same direction as the mechanical rotation of the rotor, therefore magnetic field seen from the stator is the sum of the rotor’s mechanical rotation speed plus the apparent rotation speed caused by the applied ac excitation. Likewise, when the wind turbine is operating above synchronous speed (super-synchronous operation), negative-sequence excitation is applied to the rotor, causing the apparent field rotation to be opposite of the rotor’s physical rotation direction. In both


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sub-synchronous and super-synchronous operation, the frequency and phase sequence of the applied rotor excitation is such that the net magnetic field rotation, as seen by the rotor, is at the synchronous speed. In sub-synchronous operation, real power must be applied to the rotor in order to create the forward-rotating apparent field rotation. This power is derived from the stator output power, via the back-to-back power converter. During super-synchronous operation, the flow of real power is out of the rotor. This power is converted to the grid frequency, and added to the power produced in the stator winding.

A DFG can appear similar to a synchronous machine, because its rotor’s flux rotates at synchronous speed. However the operational behavior is quite different. The inherent characteristics of the DFG machine provide fast control of the real and reactive power output of the wind turbine. These characteristics are the controllability of the voltage-source converters used in the machine, and the fact that ac excitation of the rotor necessitates a laminated rotor design. A laminated rotor results in very short rotor flux time constants; far shorter than those of a synchronous generator. In practice, these factors yield an approximately constant source of real power and voltage regulation response that is much faster than the response of a synchronous generator; more akin to a STATCOM.

The phase angle of the ac excitation applied to a DFG’s rotor establishes the phase angle of the stator internal source voltage, primarily affecting the flow of real power. The magnitude of the excitation determines the magnitude of the source voltage, primarily affecting reactive power flow out of, or into the stator winding. Because the power converter responsiveness and the very short time constants of the laminated rotor allows extremely fast control of the applied rotor excitation, the real and reactive power of a DFG machine can be precisely controlled at high bandwidth. The control of real power plays a critical role in mitigating mechanical loads imposed on the wind turbine. The fast control of reactive power provides voltage regulation capability approaching that of a STATCOM, which is instrumental in achieving stringent low-voltage ride-through requirements imposed by most grid codes today. Because of these LVRT requirements, and the aerodynamic efficiency advantages of variable speed operation, DFG and full conversion wind turbine technologies have largely supplanted the simple induction generator technologies in North America and other markets.

DFG Balanced Fault PerformanceThe previous description of the DFG wind turbine generators pertains to the normal steady-state operation, as well as operation during mild to moderate faults. Severe faults cause excessive voltage to be induced onto the machine’s rotor, which are, in turn, imposed on the power converter. It is not economical to design the converter to withstand the voltages and currents imposed by the most severe faults. Thus, a crowbar function is used in practice to divert the induced rotor current. There are various approaches to achieving this crowbar functionality, including:

• A shorting device (typically using thyristors) connected in shunt between the machine’s rotor and the rotor-side power converter. The crowbar may include some impedance in the shorting path. This option is illustrated in Figure 1.

• Shorting of the rotor via switching of the rotor-side power converter.• A chopper circuit on the converter’s dc bus, to limit dc bus voltage by diversion of some

or all of the current coming from the rotor. (This is not actually a crowbar action, per se, because the rotor is not directly shorted and the rotor-side converter remains in operation, but achieves much of the same goal.)


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While the crowbar function is engaged, the DFG generator effectively becomes an induction generator. In this crowbarred state, the fault behavior is defined by the flux equations of the physical machine. When the crowbar is not engaged, however, the machine operates according to its control design. Unlike induction machine fault current performance, which is established by the physics of the machine, there is a wide range of possibilities in the design and objectives of DFG generator controls. Variations can be wide between different manufacturers, and even different models from the same manufacturer. Control design practices evolve over time, in response to changing grid requirements and equipment capabilities. For balanced faults of insufficient severity to cause crowbar action, some generalized and typical characteristics of DFG generator performance are:

• The generator will tend to hold constant real power output for remote faults that do not cause a large drop in voltage.

• The controls may hold the reactive power output constant for a remote fault, or the control may respond to increase the reactive power output in order to support the terminal voltage. The increased reactive power may be via a closed-loop voltage regulation function or by a programmed open-loop reactive power versus voltage magnitude characteristic.

• For more severe faults, maintaining constant power and/or increased reactive power would result in excessive current due to the decreased terminal voltage. The generator may transition to a current-limited mode. This current limit may be fixed, or may be time dependent.

• For even more severe faults, there may be precedence given for reactive output over real power output.

In addition to the variations in controlled behavior, the criteria for applying, and removing, the crowbar function can also vary widely. Different measures may be used for the crowbar threshold, such as rotor ac current or dc bus voltage, as well as different magnitude thresholds for each of these measures. In older designs, once a machine was crowbarred, it was tripped. Thus there was no removal of the crowbar while in operation. This, however, is incompatible with current fault ride-through requirements. Different designs may use different criteria for crowbar removal. In one current DFG design, a three-phase fault within a wind plant, or very near to its transmission interconnection, might result in application of the crowbar for several cycles of the fault duration with crowbar removal possible before the fault is cleared. Faults in the transmission system away from the interconnection bus result in no crowbar action with this design. Other designs may trigger the crowbar for any large drop in terminal voltage, and the crowbar may remain until the fault is cleared.In summary, there are basically three different regimes of fault current behavior for DFG wind turbines, depending on fault severity:

• Very severe faults where the crowbar is applied and not removed, thus providing the fault current performance of a simple induction machine.

• Faults of insufficient severity to cause crowbar operation, for which injected currents are controlled and performance is very similar to a full conversion wind turbine (inverter).

• Faults of intermediate severity where the nonlinearities of crowbar operation are critical, resulting in complex behaviors.

Figure 2 illustrates short-circuit current contribution of a typical DFG wind turbine to a long duration three-phase fault that reduces the voltage at the MV terminals of the unit transformer to 20% of nominal. Copyright © 2014 IEEE. All rights reserved. This is an unapproved IEEE Standards Draft, subject to change. page 168

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In this case, the crowbar was activated for the first two cycles, and removed by the generator’s controls while the fault was still present. After the removal of the crowbar, the generator contributes approximately 1.2 p.u. current continuously. This current is ordered by the controls to provide reactive support of the grid voltage, and is limited to the value shown. If the impedance to the fault were twice as large, and the machine terminal voltages depressed only half as much, the continuous fault current contribution would still be essentially the same. Thus, the controlled behavior of the DFG cannot be adequately characterized by a voltage in series with a reactance.

Figure 3: Short-circuit current from a Type III wind turbine generator for a fault reducing the voltage at the unit step-up transformer MV terminals to 20%.

DFG Unbalanced Fault PerformanceThe behavior of DFG wind turbines during unbalanced faults is substantially dissimilar to the behavior of conventional synchronous and induction generators. Both of these conventional generator types appear as a Thevenin voltage source in the positive phase sequence and passive impedance in the negative phase sequence. Positive and negative sequence performance are fully decoupled in the models for conventional generators, which is a fundamental assumption of the symmetrical component analysis used in all short-circuit analysis software.Current imbalance results in unequal current in the legs of the power electronic converters of DFG generators and ripple in the converter’s dc link voltage. Because of the inherent controllability of DFG generators, they can be controlled to create a negative sequence voltage source to oppose the flow of negative sequence currents and thus attempt to maintain balanced current despite the presence of the unbalanced fault. Active opposition of current imbalance is a means to protect the power converter from excess current duty. The ability of the converter to perform this negative sequence opposition is limited by converter variables that are also affected by the positive sequence behavior. Thus, the positive and negative sequence behaviors are coupled; and the negative as well as positive sequences contain active sources. Both of these factors pose a fundamental conflict with the generator representation practices of short-circuit software programs.

A DFG that is continuously crowbarred responds to unbalanced faults just as would an induction machine, and can be readily and accurately modeled by existing short-circuit analysis tools. However, the crowbar may be engaged and disengaged during the fault, possibly in a cyclic fashion switching in


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and out during portions of each cycle. This cannot be modeled by any phasor-domain short-circuit analysis tool.

DFG Fault ModelingThe fault behavior of a DFG is complicated by the inherent discontinuous behavior between the normal and crowbarred states. And, in the non-crowbarred state, the behavior is substantially the product of control designs based on a wide range of possible design philosophies and equipment capabilities. Thus, it is not possible to describe a generic short-circuit model for DFG wind turbine generators with any degree of accuracy over the range of possible fault severities.Fortunately, the maximum fault current results from the crowbarred state, and the short-circuit behavior when crowbarred can usually be calculated using existing short-circuit analysis software and the generator’s physical parameters. This maximum current can be calculated using the generators sub-transient reactance, typically on the order of 0.2 per unit on generator rating. Maximum current is the limiting condition for purposes such as determining equipment fault current withstand. Protective relaying and fusing must be coordinated over the full range of operating conditions. Because a wind plant may not be operating at a given time, the short-circuit contribution varies from zero (with no wind turbines in operation) to the maximum current with all turbines operating and in the crowbar condition for a close-in transmission fault. Also, fault current contributions from DFG wind turbines, particularly when operated in the controlled state, tend to be dwarfed by the typically much larger contributions from other sources in the transmission grid. Thus, detailed and highly accurate of DFG wind turbines in the controlled (non-crowbarred) state may not be routinely needed.

Where highly accurate short-circuit modeling is necessary, phasor-domain short circuit analysis tools do not have sufficient capability, and the only recourse is detailed electromagnetic transient (EMT) simulation. EMT programs are fully capable of modeling wind turbines in great detail, sufficient to perform any needed short-circuit current analysis. While the use of such tools may be justified in certain instances, there are major shortcomings impeding their widespread use for short circuit analysis involving variable-speed wind turbines. These shortcomings are:

• Short circuit analysis is typically performed with relatively large and complex network models. EMT type programs are generally cumbersome and inefficient for large-system modeling.

• The technical communities typically involved in short-circuit analysis, typically protection engineers, are generally unaccustomed to using EMT programs. Use of such programs requires specialized skills.

• EMT models of wind turbines require highly detailed models of controls in order to provide meaningful results. The information needed to develop such control models is typically considered highly proprietary by wind turbine manufacturers, and is unlikely to be made available to third parties needing to perform short-circuit analysis without legal entanglements like non-disclosure agreements, as dissemination of the models could compromise the manufacturer’s intellectual property.

As a result, EMT programs cannot be considered as a practical means for performing short-circuit analysis in general.


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MV

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When perturbation signals are opposite in phase, the islanding detection scheme could not be effective because of the cancellation of perturbation signals.

When perturbation signals are in phase, the islanding detection scheme could degrade power qualities with large disturbance by aggregate perturbation signal.

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Annex J (Informative) – “Frequency Feedback Method with Step Injection” (Japanese Experience with new Anti-islanding Technology of Inverter-based DR)

Background of development

When the delivery of power from substation to distribution line stops due to ground fault, short-circuit accident or planned power outage in a distribution system where DR are interconnected, it is necessary to disconnect the DR with certainty to prevent negative impacts on section switches and to secure worker safety on the distribution line. High penetration of DR means that multiple PV systems (for example) may be connected to the same distribution line. When PV inverters are connected in a high density, perturbation signals of active anti-islanding protection function mounted on each PV inverter may cause mutual interference as shown in Fig.1.

These are shown in Fig. 1 below.

(a) Perturbation Signals are in Phase (b) Perturbation Signals are Opposite in Phase

Fig.1. Interference of Perturbation Signals of Active Anti-Islanding Protection

When unintentional islanding occurs, DR ceases to energize the Area EPS with certainty, resulting in unintentional islanding. Unintentional islanding can- pose a threat to the public, emergency response personnel, and utility workers; - lead power quality problems that will affect the Area EPS and local loads; and- cause major damage to the DR using the rotation machine because of out-of-phase closing.(See IEEE Std 1547.2-2008 8.4 for details.)

Inverter-based small-scale DR is, therefore, generally equipped with an active anti-islanding protection.


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Under high penetration of inverter-based small-scale DR, especially PV, it is conceivable that active anti-islanding protection can result in problems due to the interference of perturbation signals. For example, - Active anti-islanding protection could fail to detect islanding within an appropriate time frame due to cancellation of perturbation signals.- Active anti-islanding protection could degrade power quality within the Area-EPS under normal condition due to the aggregation of perturbation signals.

An example of delay in islanding detection due to cancellation of perturbation signals of active anti-islanding protection is shown in Fig 2 below. When perturbation signals are synchronized, they are not cancelled out and inverter-based DR can cease energizing the Area EPS at about one hundred milliseconds following the formation of an island. However, when they are not synchronized, it takes more than two hundred milliseconds to cease energizing the Area EPS because of cancellation of perturbation signals under active anti-islanding protection.


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In general, the delay in islanding detection due to cancellation of perturbation signals tends to increase with the number of DRs interconnected to the island. Fig.3 shows the result of a field test in which the time delay for islanding detection is observed to increase with the number of DR interconnected to the Area EPS.

Perturbation signals could be cancelled out even if all the inverter-based DRs in the island employ the same type of active anti-islanding protection method. In addition, if the method to detect frequency is different, the behavior of perturbation signals (direction, cycle, etc.) would become different, thereby creating an adverse impact to islanding detection. This is more likely to happen as the number of DR in the island increases.

Increased delay in islanding detection may result in the failure of detection within the prescribed time. Under high penetration of DR, the above-mentioned results show that greater consideration is required to avoid the possibility of failure of islanding detection due to cancellation of perturbation signals of active anti-islanding protection, as well as the power quality degradation of the Area EPS under normal conditions due to large disturbance by aggregate perturbation signal.

One of the solutions to this problem is to conduct tests to verify that there is no problem, even when a number of different inverter-based DRs are interconnected to the Area EPS. However, there are various types of active anti-islanding protection methods and testing procedures that vary by manufacturer, which leads to an enormous number of combinations of inverter-based interconnection systems, requiring considerable time and effort to perform the combination tests.


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Fig.3 Increase in islanding detection delay with multiple DR in the island

New Anti-islanding Technology - Frequency Feedback Method with Step-injection

To solve the problems mentioned above, a new type of active anti-islanding protection method, called “Frequency Feedback Method with Step Injection” was developed in Japan.6

The control algorithm of the method can be summarized as follows:

6 The “Frequency Feedback Method with Step-injection” was developed in the project called “Research for demonstration of concentrated interconnection system of solar power generator” led by NEDO, New Energy and Industrial Technology Development Organization. It is established as the industry standard by JEMA, the Japan Electrical Manufacturers’ Association.

This method is also described in the private sector code “Grid Inter-connection Code” (JESC E0019) as an active anti-islanding protection method which is effective when multiple inverter-based DRs are interconnected.


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- Perturbation signals are not injected into the Area EPS when the system is in normal condition.- By detecting rapid change in total harmonic distortion (THD), stepwise reactive power will be injected to accelerate change in frequency of the island.- By injecting reactive power in proportion to change of frequency, perturbation signals of all the inverter-based DRs in the island are synchronized so that there is no cancellation of perturbation signals. - Frequency change is further assisted by applying positive feedback to reactive power injection.

Applying this active anti-islanding protection method to all inverter-based DRs in the Area EPS solves two problems at the same time:

- failure in islanding detection due to cancellation of perturbation signals and- power quality degradation in the Area EPS by perturbation signals.

Moreover, it is verified in field tests that this active anti-islanding protection method will enable all inverter-based DR to cease to energize the Area EPS within 0.2 seconds, even when generation output and demand in the island are balanced under high penetration of DR. Also, this method can be combined with FRT (Fault Ride Through) function without causing DR to trip unnecessarily due to an increase/decrease in voltage/frequency when connected.

To realize the above-mentioned control algorithm, two functions are combined in the new anti-islanding method: frequency feedback and reactive power step injection.

New Islanding Detection MethodFrequency feedback method with step

injection＝＋Frequency feedback

functionStep injection

function


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Reactive Power Injection(Perturbation Signal)

When frequency change is small reactive power injection is maintained small to avoid degrading power qualities of the Area EPS.

Frequency Change


Frequency feedback functionThe frequency feedback function calculates reactive power injection from the change in frequency from the past and injects the reactive power. The change in the frequency is amplified by positive feedback of frequency when an island is created.

The Inverter controls output current phase based on system frequency. If the change in frequency is positive, control to advance output current phase is performed continuously. In an islanding operation, this makes frequency to synchronize to output current phase. And, because of continuous control to advance output current phase, when the change in frequency becomes greater, islanding can be detected. In the same way, when the change in frequency is negative, changes in frequency become greater by continuous control to delay output current phase and islanding can be detected.

Fig.4 shows the characteristic of reactive power injection in the frequency feedback function. In the range where frequency change is small, the reactive power injection is maintained small so as to avoid the negative impact on power quality of the Area EPS in normal condition. And, when frequency change exceeds the predefined threshold, the magnitude of reactive power injection is increased to immediately amplify frequency change by positive feedback.

Fig.4 Characteristic of reactive power injection in the frequency feedback function


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The voltage and frequency in the island are governed by the following:

P=V 2

RQ=V 2( 1

2 πf⋅L−2 πf⋅C)

where P(W) : Active power output of inverter-based DR, i.e. active power of load, Q(var) : Reactive power output of inverter-based DR, i.e. reactive power of load, V(Volt) : Voltage, R(ohm) : Resistance of load, L(H) : Inductance of load, C(F) : Capacitance of load, and f(Hz) : Frequency.

Assuming that the balance of active power is being maintained in the island, frequency will decrease with reactive power injection by inverter-based DR. Conversely, frequency will increase with reactive power absorption by inverter-based DR according to the above formula.

The equivalent circuit of the island is shown in Fig 5 below.

Fig.5 Equivalent Circuit of an Island

Once frequency of an island decreases all the inverter-based DRs in the island concurrently inject reactive power to further decrease the frequency of the island. On the other hand once the frequency of the island increases all the inverter-based DRs in the island concurrently absorb reactive power to further increase the frequency of the island. Accordingly, cancellation of perturbation signals injected by inverter-based DRs should not occur with this active anti-islanding protection.

Moreover in normal condition there will be less impact on the power qualities of the Area EPS because the aggregate reactive power injected to the Area EPS is small enough.


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Step-injection of reactive power functionWhen generations and loads are completely balanced in an island, the frequency in the island cannot be changed by frequency feedback function because the frequency in the island does not change with the formation of the island.

Therefore, after detecting the rapid change in total harmonic distortion, stepwise reactive power will be injected for three cycles to generate change in frequency of the island. All the inverter-based DRs inject stepwise reactive power uniformly to decrease frequency, so that cancellation of reactive power injection won’t occur. Once change in frequency is detected, frequency feedback function will magnify the frequency change in the island by positive feedback. Thus, unintentional islanding can be detected.

citationY. Miyamoto, T. Sato, M. Ropp, S. Gonzalez, A. Ellis, “Anti-islanding technology for high penetration residential PV systems,” Cigre SC C6 Colloquium 2013

Sandia……


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Annex K (Informative) – Advanced DR Functions for Supporting the EPS

DR systems are capable of providing many functions that support power system operations and contribute to grid benefits. Many of these inverter-based functions are described in the Advanced Functions for DR Systems Modeled in IEC 61850-90-77.

Some of these DR functions are becoming crucial for grids that have high penetrations of DR systems. The implementation of these crucial DR functions can avoid the possible need to retrofit DR systems during the course of their useful life or their contractual period, as unfortunately occurred in Europe. Many of those DR functions have already been implemented in Europe, are included in many DR products, and are expected to be increasingly required for grid operations in North America.

Most DR systems can or must operate autonomously in order to respond rapidly to changing power system conditions and meet power system safety, reliability, and efficiency criteria. At the local level, DR systems must manage their own generation and storage activities autonomously, based on local conditions, pre-established settings, and DR owner preferences. However, communications with utilities, facility energy management systems, and/or retail energy providers can support additional functions and provide updated functional parameters, so that the DRs can participate more effectively in the management of the Area EPS. But direct control by utilities is not feasible for the thousands if not millions of DR systems connected to the distribution system, so a hierarchical approach is necessary for utilities to interact with most of these widely dispersed DR systems.

In some situations, utilities may request or require DR systems to be located at critical electrically important points, while utility assessments of new DR implementations may determine which DR functions could be preferred or even mandatory for providing grid support. For any DR systems to be active participants in grid operations, their operations must be coordinated with other DR systems and with distribution grid equipment such as load tap changers, capacitor banks, and voltage regulators.

Many commercial and industrial customer sites would likely include Facility DR energy management systems (FDEMS) that could modify DR autonomous settings and issue direct commands. The Area EPS operators could interact with these FDEMS occasionally to update settings or broadcast pricing signals and/or emergency commands. In addition, the distribution-level area EPS operators could provide some of the DR benefits to regional transmission organizations (RTOs) and/or independent system operators (ISOs) for reliability and market purposes. In some regions, retail energy providers (REPs) or other energy service providers (ESPs) would be responsible for managing groups of DR systems.

Table 3 describes the main DR functions that can support EPS performance and indicates their benefits to the grid, as well as related planning issues, operational issues, and information requirements. The following terms with their definitions are used in this table.

7 See “Advanced Functions for DR Systems Modeled in IEC 61850-90-7” at http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/IEC61850-7-420_Overview . The actual IEC 61850-90-7 Technical Report is available through the IEC.


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Term Definition (These terms could be added to the appropriate definition section of the P1547.8 document if so agreed).

Disconnected Condition of the DER system during which output of the DER to the EPS is de-energized or galvanically isolated. A disconnect condition results in a mandatory time delay before reconnection.

Cease to Export Condition where there will be no net export of current at the PCC (would require an isolation device at the PCC). The DER is allowed to continue to provide power to local loads. No mandatory time delays for reconnection are required following a Cease to Export condition.

Cease to Energize

Condition where the DER remains connected but not providing watts and vars (voltage?) at the ECP. No mandatory time delays are required for reconnection following a Cease to Energize condition.

Trip A response to an abnormal condition on the area EPS. The DER response may be “Cease to Export”, “Cease to Energize”, or “Disconnect” as required by the utility in response to the specific abnormal condition.


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Table 3: DR Functions and the Benefits of DR Integration into EPS Operations # Grid Benefit Advanced DR Function Brief Description of DR

FunctionPurposes or Scenarios for the DR Function

Planning Issues related to DR Scenarios

Operations Issues related to DR Scenarios

Information Requirements

1 Public and Personnel Safety

Equipment Preservation

Reliability and Power Quality Improvement

Anti-Islanding: Support anti-islanding in cases of unintentional islanding

DR rides through temporary voltage and frequency anomalies, but disconnects when ride-through limits are exceeded, or other signals indicate an unintentional islanded situation. There may be passive autonomous functions; active autonomous functions; and EPS activated functions.

DR trip only when voltage or frequency limits are exceeded over specified time periods as opposed to immediately, thus remaining connected for as long as possible yet disconnecting to avoid safety or damage problems

Anti-islanding protection schemes should be tested for different sizes, locations, and environments of DR units

Anti-islanding disconnections should be validated as having occurred as required

Autonomous: executionLocal: DR units monitor voltage and frequency, rate of change, voltage/frequency biases, etc.

2 Reliability Improvement

L/HVRT: Provide ride-through of low/high voltage excursions beyond normal limits within preset voltage-time limits

DR rides through temporary voltage anomalies, ceases to energize if necessary, and starts/continues to energize immediately if voltage recovers within the clearing time, but disconnects if ride-through voltage-time limits are exceeded

Fewer service interruptions will occur since the DR systems can stay connected, possibly cease to export power on lower voltage dips, but nonetheless continue or start to export power again if the voltage levels have recovered within normal limits within the time frames.

L/HVRT limits need to be studied, provided to the DR, and validated for different scenarios

Correct operation of ride-through situations should be validated

Autonomous: executionLocal: DR units monitor voltage


L/HFRT: Provide ride-through of low/high frequency excursions beyond normal limits within preset frequency-time limits

DR rides through temporary frequency anomalies, ceases to energize if necessary, and starts/continues to energize immediately if frequency recovers within the clearing time, but disconnects if ride-through frequency-time limits are exceeded

Fewer service interruptions will occur since the DR systems can stay connected, possibly cease to export power on higher and lower frequency excursions, but nonetheless continue or start to export power again if the frequency levels have recovered within normal limits within the time frames limits.

L/HFRT limits need to be studied, provided to the DR, and validated for different scenarios

Correct operation of ride-through situations should be validated

Autonomous: executionLocal: DR units monitor frequency


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# Grid Benefit Advanced DR Function Brief Description of DR Function

Purposes or Scenarios for the DR Function





Frequency-Watt: Counteract frequency excursions beyond normal limits by decreasing or increasing real power

DR decreases real power output during high frequency situations, including during L/HFRT events. DR increases real power (it if is able to do so) during low frequency situations.

Upon high frequency events including during a L/HFRT event, the DR “ceases to energize” so that no real power is exported even though the DR remains connected to the EPS. Hysteresis can be used as the frequency returns to within the normal range to avoid abrupt changes by aggregations of DR. DR increases real power (it if is able to do so) during low frequency situations.

The frequency scenarios are studied to determine the most appropriate reductions in real power for different situations.

DR responses to frequency events are monitored for use in determining updated settings

Autonomous: executionLocal: monitor frequency;Remote: update frequency-watt settings from utility, REP, or FDEMS


Power Quality Improvement

Dynamic Current Support: Counteract abnormal high or low voltage excursions by providing dynamic reactive current support

DR provides dynamically adjusted reactive current support during voltage deviations. These dynamic support actions are based on a combination of the rate of change of the voltage levels and the duration of the abnormal voltage dips or spikes.

Dynamic reactive current support during abnormal voltage conditions counteracts the voltage spikes or dips, with the goal of minimizing these and returning the voltage within normal limits.

An assessment identifies those DR units or locations for DR units where reactive current meaningfully impacts EPS voltage excursions. The dynamic reactive current settings are studied to determine the most appropriate for different DR locations, sizes, aggregations, and other considerations

After-the-fact DR information on the use and possible impact of the dynamic reactive current settings is collected.

Autonomous: executionLocal: monitor voltage anomalies;Remote: update dynamic reactive current settings from utility or FDEMS


Power Quality Improvement

Soft-Start Reconnection: Reconnect autonomously after grid power is restored

DR waits a pre-established time to ensure both voltage and frequency are within normal limits, and then either ramps up upon reconnection at a pre-established ramp rate or waits a random time within a pre-established time window to start energizing. The Area EPS could delay this reconnection (see Command DR to Delay Connection)

By either requiring DR systems to ramp up during reconnection or to reconnect randomly within a time window, the sharp transitions and consequential power quality problems of voltage spikes, harmonics, and oscillations can be avoided, including the possibility that the disruptions caused by the reconnection of large numbers of DR systems actually precipitates another power outage.

Reconnection wait times, ramp rates, and time windows need to be studied and established for different DR locations, sizes, aggregations, and other considerations

Correct operation of DR units should be validated

Autonomous: executionLocal: DR units monitor voltage and frequency to ensure they are within normal limits before reconnectingRemote: DR units receives delay connect command from utility, REP, or FDEMS


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Command DR to Connect or Disconnect or Delay Connection: Perform soft or hard connect or disconnect from grid via direct command

DR system performs a disconnect or reconnect on command from a facility energy management system or from the utility management system

The connect command is sent to the DR in order to offset local load, to provide post-contingency load shift headroom, or to provide sufficient aggregate capacity to address a circuit overload condition. The disconnect command is sent to the DR in order to avoid reverse power flow or other emergency situation.

DR is placed within the EPS at a location where output change is shown to mitigate an identified overload or other emergency condition. This requires an assessment of Area EPS to determine locations with elevated reliability risk due to loading of individual components

Monitoring of the DR status and local circuit conditions provide the necessary information for determining whether a connect or disconnect command is necessary.

Remote: DR units receive connect or disconnect commands from utility, REP, or FDEMS


Backup: Provide backup power after disconnecting from grid

DR units automatically provide power to a local EPS for backup if the facility disconnects from the Area EPS. The load is pre-selected to remain energized and the DR generation is adjusted dynamically to balance that load.

DR units are installed to provide real and reactive power at the site without offsite power

DR units are placed within the local EPS at a location with direct access to the pre-selected load

DR units provide temporary backup power to the facility upon loss of Area EPS power

Autonomous: executionLocal: DR units monitor connected load in order to balance generation and load


Support Creation and Operation of Islanded Microgrid: Disconnect from the Area EPS while establishing a pre-designed microgrid

A DR microgrid management system creates a microgrid to minimize the extent and length of power outages. The type and aggregated capabilities of the DR units within the microgrid are capable of balancing the expected loads on a sustained basis. The DR units support microgrid operations according to the settings provided by the DR microgrid management system.

DR units enter microgrid mode upon separation from the Area EPS, acting either as leading or following the microgrid frequency and voltage, some of them (or none) acting as base and other (or all) as load-following generation, as established by the microgrid management system capable of matching microgrid loads

DR units are pre-configured to be capable of operating in a microgrid

DR units are switched into microgrid mode by the DR microgrid management system and dynamically match generation to loads on a sustained basis

Autonomous: executionLocal: DR units monitor voltage and frequency at PCC; to determine if they exceed those limits established for converting to islanded microgridRemote: DR units receive microgrid mode command from utility, REP, or FDEMS


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Decrease Export of Real Power at PCC: Response to command/ requests either to increase import or to decrease export of real power

DR responds to a command from a facility energy management system, retail energy provider, or utility to decrease the export of power at the PCC. This can be achieved by decreasing generation, increasing the charging of storage units, or increasing local load.

A circuit is not capable of handling the exported power from the DR and is becoming overloaded. Decreasing the DR exported power reduces this overload.The frequency of the Area EPS is at risk for increasing beyond normal limits. Decreasing the DR exported power of large aggregations of DR can help alleviate overfrequency conditions

An assessment identifies those DR units placed at locations where excessive generation can overload the circuit. Those DR units are required to be capable of limiting export power.Aggregations of DR units are identified that can be required/requested to lower power exports upon over frequency conditions

Area EPS circuits are monitored for possible generation overload conditions and, if detected, DR units are commanded to decrease the export of power at the PCC.

Autonomous: execution once decrease command is receivedRemote: DR units receive import/export settings and commands from utility, REP, or FDEMS


Limit Maximum Real Power: Limit maximum real power output at the ECP or PCC to a preset value

DR exports power at the PCC up to the maximum limit. When near this maximum limit, the DR can remain within the limit by decreasing generation, increasing the charging of storage units, or increasing local load.

The maximum export limit is established to avoid overloading a distribution circuit and otherwise-required capital project. This autonomous action means that the Area EPS circuits do not need to be monitored in real time for possible circuit overloads due to excess generation. However, this approach may be not be optimal since actual circuit conditions may not match conditions in the assessments.

An assessment identifies those DR units placed at locations where excessive generation can overload the circuit. Those DR units are required to be capable of limiting export power.Aggregations of DR units are identified that can be required/requested to lower power exports upon over frequency conditions

Adjust real power output to the limit commanded by the utility, REP, or FDEMS

Autonomous: execution once limit is establishedLocal: Monitor output at PCC or ECPRemote: receive maximum real power export limit from utility, REP, or FDEMS


Transmission Operational Support

Congestion Reduction

Efficiency

Increase Export of Real Power at PCC: Response to command/ requests either to decrease import or to increase export of real power

DR responds to a command from a facility energy management system, retail energy provider, or utility to increase the export of power at the PCC. This can be achieved by increasing generation, increasing the discharging of storage units, or decreasing local load.

The increased export of DR power at the PCC expands otherwise-constrained post-contingency load shift or backup connection opportunities.DR responds to market prices by increasing its real power output.

An assessment is made of Area EPS locations with elevated reliability risk due to limited post-contingency load shift or backup connection opportunities. The DR within appropriate locations are contracted to respond to commands to increase exported power at the PCC, thus providing additional “headroom”.

The Area EPS is monitored for its risk level of post-contingency requirements to shift load. DR units that are capable of providing beneficial additional export power are commanded to do so.

Autonomous: execution once increase command is receivedRemote: DR units receive import/export settings and commands from utility, REP, or FDEMS


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Transmission Operational Support


Efficiency

Set Real Power: Set actual real power output at the ECP or PCC either as a specific real power setpoint or as a percentage of local load

DR responds to a command from a facility energy management system, retail energy provider, or utility to set the export of power at the PCC. The command can either be a specific real power setpoint or a percentage of local load. This can be achieved by modifying generation, modifying the charging of storage units, or modifying local load.

A base or known generation level is established for DR or its facility without the need for constant monitoring.DR responds to market prices by modifying its real power output.Another reason would be to balance load requirements more closely and thus avoid either overloads or over-generation.

An assessment identifies those locations where excessive generation from DR can overload the circuit. Those DR units are required to be capable of setting export power.

DR receives command to set real powerDR operating or likely to operate to relieve overload conditions

Autonomous: execution once setpoint is providedLocal: DR units monitor output at PCC or ECPRemote: receive real power export setpoint from utility, REP, or FDEMS

14 Reliability ImprovementEfficiency

Transmission Support


Follow Schedule of Real Power: Follow schedule of actual or maximum real power output at specific times

DR units are scheduled to export real power (or a maximum of real power) for different times of the day, week, or other time frame. DR validates and follows the schedules at the appropriate times

DR generation and storage is scheduled to take into account the expected load, the net cost of self-generation, the net cost of Area EPS power, and additional market criteria, with the purpose of managing load

DR generation and storage schedules are developed to optimize expected power system conditions, including market signals

DR units operate according to their schedules

Autonomous: execution once the schedules are received and validatedRemote: update schedules by utility, REP, or FDEMS

15 Reliability ImprovementEfficiency

Transmission Support


Follow Schedule for Storage: Set or schedule the storage of energy for later delivery, indicating time to start charging, charging rate and/or “charge-by” time

The utility, facility EMS, or DR unit establishes and executes storage charging and discharging schedules for time period ranging from minutes to hours to days or more. “Charge-by” times permit flexibility in exactly when charging is executed, so long as it is completed by the specified time. DR validates and follows the schedules at the appropriate times

The DR storage schedules are designed to perform peak shaving and/or to mitigate a possible circuit overload or over-generation at specific times.The DR storage schedule can also be designed to manage local loads more efficiently based on tariffs and/or market signals.“Charge-by” schedules are particularly useful for electric vehicles to ensure they are ready to drive

DR storage schedules are developed to optimize expected power system conditions, including market signals

DR storage schedules are monitored to ensure they are providing the expected load management results

Autonomous: execution once the schedules are received and validatedRemote: update storage schedule by Utility, REP, or FDEMS


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16 Power Quality Improvement

Efficiency/ CVR

Volt-Var Control: Execute volt-var control in response to settings that define reactive power output for different voltages

DR monitors local voltage and modifies either available vars (vars that do not impact real power output) or total vars to counteract changes in increases and decreases of voltage within the normal range. Deadbands may be used to minimize unnecessary fluctuations of var changes, and hysteresis may be used to avoid hunting as voltages shift

In coordination with load tap changers, capacitor banks, and voltage regulators, DR units can counteract voltage increases or decreases to help stabilize voltage levels on circuits and help maintain them within the normal limits. DR volt/var responses can also help maintain CVR voltage levels.

DR volt/var settings are studied to determine the most effective for different types, locations, sizes, and aggregations of DR on different types of circuits, including at different times of day or week. These volt/var settings need to be coordinated with other distribution equipment settings. This requires a detailed assessment of Area EPS voltage conditions.

The real-time results are monitored of the coordinated settings of DR and other distribution equipment to ensure adequate if not optimal settings for most scenarios.

Autonomous: execution,Local: monitor voltage;Remote: update volt-var settings from utility, REP, or FDEMS


Operate by Fixed Power Factor: Provide reactive power by a fixed power factor

DR provides a fixed power factor

DR helps to compensate for different types of loads and better maintain feeder voltage at nominal without actively changing vars. However cannot actively respond to voltage changes

The most appropriate fixed power factor for the DR is established through studies of the impact of power system equipment and loads on its circuit.

DR power factor is reviewed periodically to determine if the setting is still the most appropriate.

Autonomous: executionRemote: set power factor command from utility, REP, or FDEMS


Define Use Ramp Rates: Use the different ramp-up and ramp-down rates that have been defined for normal, emergency, and reconnection

DR real power ramp-up and ramp-down rates are established for normal, emergency, and reconnection scenarios. Additional ramp rates may be established for schedules, vars and other transitions.

Ramping DR real power output helps avoid sharp transitions and the consequential power quality problems of voltage spikes or dips, harmonics, and oscillations.

Ramp rates are studied to determine the most effective for different types, locations, sizes, and aggregations of DR on different types of circuits, while still not impacting the benefit of exporting as much real power as possible.

The real-time impacts of ramping are monitored to ensure compliance and better understanding of those impacts

Autonomous: executionRemote: update ramp rates from utility, REP, or FDEMS


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Voltage Smoothing: Modify real power output in response to local voltage variations

DR modifies its real power output to counteract voltage variations while voltage still remains within normal limits

DR counteracts voltage variations through changes in real power for the purpose of remaining within CVR limits or minimizing voltage fluctuations due to impacts from nearby loads or other DR. This function may be used if reactive power is not feasible or may be used in conjunction with volt-var control

DR voltage watt settings are studied to determine the most effective for different types, locations, sizes, and aggregations of DR on different types of circuits, while still not impacting the benefit of exporting or importing as much real power as possible.

The results from DR voltage smoothing actions are collected and analyzed to better understand the impacts of the actions and possibly modify the settings

Autonomous: executionLocal: monitor voltageRemote: update voltage smoothing settings from utility, REP, or FDEMS


Bulk Generation Support

Frequency Smoothing: Smooth minor frequency deviations by rapidly modifying real power output to counteract these deviations

DR modifies its real power output to counteract frequency variations while frequency still remains within normal limits

DR counteracts frequency variations through rapid changes in real power for the purpose of minimizing frequency fluctuations that can be more costly for bulk generators to counter.In particular, charging of electric vehicles can implement this function while still ensuring that the electric vehicle is charged by the time it is needed

Studies can be made to determine optimal settings for modifying real-power in response to different types of frequency variations

The results from DR frequency smoothing actions are collected and analyzed to better understand the impacts of the actions and possibly modify the settings

Autonomous: executionLocal: monitor frequencyRemote: update frequency smoothing settings from utility, REP, or FDEMS

21 Ancillary Services


AGC: Support frequency regulation by direct automatic generation control (AGC) commands

DR modifies its real power output in response to AGC commands

DR provides frequency support as an ancillary service to utility automatic generation control. The most effective would be for large aggregations of DR to provide this ancillary service, such as virtual power plants, actual power plants, or large EV charging stations.

Studies determine how much AGC support could be provided by specific aggregations of DR under different scenarios

AGC control commands are issued every few seconds to the DR units

Remote: Receive AGC commands to modify real power output


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Operational Reserves: Provide “spinning” or operational reserve by increasing real power from generation or storage as bid into market and upon command

Upon command, the DR provides the incremental energy capacity which has been bid into the energy market.

DR provides operational energy either immediately or within a contracted longer term. DR that can increase real power upon command, such as energy storage units, can participate. Aggregations of DR such as DR power plants are most likely to be effective. DR can support bulk generation which may not be able to respond as quickly

DR is assessed to determine if operational reserves are possible and will not negatively impact local circuits and equipment.

Command to increase real power to the contractual level is issued. Monitoring determines if DR is providing the contractual real power

Remote: Increase real power output command to contractual level from utility, REP, or FDEMS


Black Start Capability: Provide black start capabilities upon command

Upon command, the DR participates in initiating recovery from outages within an EPS that has no external source of energy.

DR which is capable of starting without offsite power is used to provide energy to a local EPS which can eventually be connected to other local EPS to eventually join the Area EPS. Black start DR can minimize the time that a local EPS is without power.

DR is assessed to determine if it can provide black start capabilities within it local EPS, and whether that EPS can eventually be interconnected with other EPSs.

Command to start exporting real power is issued. Monitoring determines if the DR is providing the contractual real power. Local EPS is eventually connected with other EPSs.

Remote: Black start mode command from utility, REP, or FDEMS

24 Emission Reduction

Emission-constrained Dispatch : Set output real power on command, based on emissions produced

Utility, REP, or FDEMS selects which DR units are to generate how much energy in order to meet emission constraints, and issues appropriate commands to these DR units

DR units are emission-constrained so that their use is limited and must be managed. Using DRs within their emission constraints benefits the overall emission reduction goals.

DR is assessed to determine the types and amount of emissions it creates and are ranked from these assessments

DR output information is collected to determine the amount of emission reductions it contributed

Autonomous: executionRemote: Receive setting for output energy from utility, REP, or FDEMS

25 Enables or enhances other benefits

Support Situational Awareness: Provide real-time or near-real-time DR information

DR provides alarms and supporting alarms, actual status, DR output measurements, local power system measurements, and other real-time and near-real-time data

DR real-time or near-real-time information provides (possibly aggregated) data to the utility, REP, and/or FDEMS in order to support real-time and short-term analysis applications.

Real-time or near-real-time information requirements from DR are assessed to determine which data should be used as input to which energy management applications

DR real-time or near-real-time information is monitored, collected, aggregated, and assessed for validity

Remote: provide DR information to utility, REP, and/or FDEMS


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26 Enables or enhances other benefits

DR Registration: Provide operational characteristics at initial interconnection and upon changes

DR nameplate information and other characteristics are provided to the utility, REP, and/or FDEMS

DR operational characteristics provides base information for use in energy management applications

DR operational characteristics are assessed to determine which data should be used as input to which energy management applications

DR operational characteristics may be collected to determine if there are any changes.

Offline or Remote (may be prior to installation): Provide DR operational characteristics to utility, REP, or FDEMS


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Annex L (Normative) -- Glossary

Glossary

Secretary’s note: the following are terms copied from other standards but included here for convenience of the reader)


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